Prospectus
Table of Contents

As Filed Pursuant to Rule 424(b)(3) Registration No. 333-113775

PROSPECTUS

 

CONSOL ENERGY INC.

 

16,622,932 shares of common stock

 


 

We are furnishing this document to allow the selling stockholders identified in this prospectus to sell up to an aggregate of 16,622,932 shares of our common stock. The selling stockholders may sell these shares from time to time in underwritten offerings, in regular brokerage transactions, in transactions directly with market makers or in privately negotiated transactions.

 

We will not receive any of the proceeds from the sale of the shares by the selling stockholders. The selling stockholders will pay all brokers’ or underwriters’ discounts and commissions, transfer taxes, and fees and disbursements of any counsel to the selling stockholders, if any.

 

Our common stock is listed on the New York Stock Exchange under the symbol “CNX”. On March 15, 2004, the last reported sales price of our common stock as reported on the New York Stock Exchange was $25.01 per share.

 

We urge you to read carefully the “ Risk Factors” section beginning on page 2 where we describe specific risks associated with an investment in our company and these securities before you make your investment decision.

 


 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

 

The date of this prospectus is March 30, 2004


Table of Contents

TABLE OF CONTENTS

 

     Page

PROSPECTUS SUMMARY

   1

RISK FACTORS

   2

FORWARD-LOOKING STATEMENTS

   14

USE OF PROCEEDS

   14

MARKET FOR COMMON STOCK

   14

SELECTED FINANCIAL DATA

   15

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

   19

BUSINESS

   53

MANAGEMENT

   87

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   97

PRINCIPAL AND SELLING STOCKHOLDERS

   97

DESCRIPTION OF CAPITAL STOCK

   103

PLAN OF DISTRIBUTION

   107

LEGAL MATTERS

   108

EXPERTS

   109

WHERE YOU CAN FIND MORE INFORMATION

   109

INDEX TO FINANCIAL STATEMENTS

   F-1


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PROSPECTUS SUMMARY

 

You should read the entire prospectus, including the information set forth in “Risk Factors” before making an investment decision.

 

CONSOL Energy

 

We are a multi-fuel energy producer and energy services provider that primarily serves the electric power generation industry in the United States. That industry generates approximately two-thirds of its output by burning coal or gas, the two fuels we produce. At December 31, 2003, we produced high-Btu bituminous coal from 20 mining complexes in the United States and Australia. Coal produced from our mines has a high-Btu content which creates more energy per unit when burned compared to coals with lower Btu content. As a result, coals with greater Btu content can be more efficient to use. We also produce pipeline-quality coalbed methane gas from our coal properties in Pennsylvania, Virginia and West Virginia and conventional gas from our properties in Tennessee and Virginia. We believe that the use of coal and gas to generate electricity will grow as demand for power increases.

 

Historically, we rank among the largest coal producers in the United States based upon total revenue, net income and operating cash flow. Our production of approximately 60 million tons of coal in 2003 accounted for approximately 5% of the total tons produced in the United States and approximately 12% of the total tons produced east of the Mississippi River during that year. We are one of the premier coal producers in the United States by several measures:

 

  We mine more high-Btu bituminous coal than any other United States producer;

 

  We are the largest coal producer, in terms of tons produced, east of the Mississippi River;

 

  We have the second largest amount of recoverable coal reserves among United States coal producers; and

 

  We are the largest United States producer of coal from underground mines.

 

We also rank as one of the largest coalbed methane gas companies in the United States based on both our proved reserves and our current daily production. Our industry position is highlighted by several measures:

 

  We possess one of the largest coalbed methane reserve bases among publicly traded oil and gas companies in the United States with approximately 1.0 trillion cubic feet of net proved reserves of gas;

 

  Our principal coalbed methane operations produce gas from coal seams with a high gas content;

 

  We currently have approximately 146 million cubic feet of gross average daily production;

 

  At December 31, 2003, we operated more than 1,500 wells connected by approximately 800 miles of gathering lines and associated infrastructure; and

 

  Our facilities have the capacity to transport 250 million cubic feet of gas per day.

 

Additionally, we provide energy services, including terminal services, industrial supply services and coal waste disposal services. We are developing our land assets that we previously used primarily to support our coal operations.

 

CONSOL Energy was organized as a Delaware corporation in 1991. Our address is CONSOL Plaza, 1800 Washington Road, Pittsburgh, Pennsylvania 15241-1421 and our telephone number is (412) 831-4000.

 

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RISK FACTORS

 

Investing in our securities will be subject to risks, including risks inherent in our business. The value of your investment may decline and could result in a loss. You should carefully consider the following factors as well as other information contained in this prospectus before deciding to invest in our securities.

 

We have a significant amount of debt compared to our stockholders’ equity, which limits our flexibility, imposes restrictions on us and could hinder our ability to compete and meet future capital and liquidity needs.

 

At December 31, 2003, we had outstanding approximately $564 million in aggregate principal amount of indebtedness, including capital leases, and total stockholders’ equity of $291 million. We have become leveraged as a result of our policy of paying dividends. Since 1992, we have paid dividends aggregating $1.2 billion, approximately the amount of our aggregate net income for the same period.

 

The degree to which we are leveraged could have important consequences to us, including the following:

 

  a portion of our cash flow must be used to pay interest on our indebtedness and therefore is not available for use in our business;

 

  our indebtedness increases our vulnerability to changes in general economic and industry conditions;

 

  our ability to obtain additional financing for working capital, capital expenditures, general corporate purposes or other purposes could be impaired;

 

  because some of our borrowings are short-term or at variable rates of interest, we are vulnerable to interest rate fluctuations, which could result in us incurring higher interest expenses if interest rates increase; and

 

  our failure to comply with covenants and restrictions contained in the terms of our borrowings could lead to a default which could cause all or a significant portion of our debt to become immediately payable.

 

Stockholders’ equity was reduced by comprehensive losses of approximately $9 million in 2003, $56 million in 2002 and $37 million in 2001. These losses relate primarily to the recognition of a minimum pension liability as a result of the negative return on plan assets for non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer retirement plans. Our minimum pension liability generally is calculated annually and reflects a number of factors including conditions in the stock markets and interest rates. We cannot predict whether we will be required to recognize such losses in the future. Further comprehensive losses would reduce our stockholders’ equity and possibly preclude us from paying dividends, which likely would adversely affect our stock price. For these and other reasons, we may not pay dividends at the same levels as in recent periods or at all.

 

The SEC has informed us that it is conducting an inquiry regarding certain matters, which may include allegations contained in an anonymous letter that certain directors and senior executive officers have misappropriated corporate funds and other assets and engaged in other illegal or inappropriate activities.

 

We received a copy of an anonymous letter addressed to the SEC and delivered to our independent auditors, PricewaterhouseCoopers LLP. The letter, and other anonymous letters received subsequently, contains numerous allegations including assertions that certain directors and senior executive officers have misappropriated corporate funds and other assets and engaged in other illegal or inappropriate activities. We have been informed that the SEC commenced an informal, non-public inquiry in October 2003 regarding certain matters, which may be related to the anonymous letter. If the SEC determined to bring an action against us, it could have a material adverse effect upon us, our financial statements and the value of our common stock.

 

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We reported losses in recent periods and we may incur losses in future periods.

 

We reported a net loss of $7.8 million in the twelve months ended December 31, 2003. Although we reported net income for each of the twelve months ended December 31, 2002, the six months ended December 31, 2001 and the twelve months ended June 30, 2001, net income was attributable to income tax benefits in the periods ended December 31, 2002 and 2001 and benefited substantially from an export sales excise tax resolution in the twelve months ended June 30, 2001. For the twelve months ended December 31, 2003 and 2002 and the six months ended December 31, 2001, we incurred losses before income tax benefits of $33.5 million, $40.4 million and $19.6 million, respectively. Our results reflect a number of factors in each period. For example, a decrease in tons of coal produced and tons of coal sold as a result of higher than usual customer inventory levels, decreased average sales price for gas in the industrial sector and lower demand for gas during the 2001-2002 winter heating season resulted in high levels of gas storage. During the fourth quarter of 2003, results were adversely affected by production problems at a number of mines. These and other conditions, including conditions beyond our control, could continue to affect our business, and we may incur losses in the future.

 

If we determine that some or all of our deferred tax assets will not be realized then we will need to reduce our deferred tax assets which could materially reduce our operating results and stockholders’ equity and possibly preclude dividend payments.

 

We account for our income taxes in accordance with Statement of Financial Accounting Standard No. 109, “Accounting for Income Taxes,” which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. Statement of Financial Accounting Standard No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2003, we had deferred tax assets in excess of deferred tax liabilities of approximately $535 million. The deferred tax assets are evaluated periodically to determine if a valuation allowance is necessary. Realization of our deferred tax assets is principally dependent upon our achievement of projected future coal and non-coal mining regular taxable income. Our judgments regarding future profitability may change due to future market conditions, our ability to continue to successfully execute our business strategy and other factors. These changes, if any, may require possible valuation allowances to be recognized. These allowances could materially reduce our operating results and stockholders’ equity and possibly preclude dividend payments, which likely would adversely affect the price of our common stock.

 

We may need substantial additional financing in order for us to fund our operations, capital expenditures and to meet other obligations.

 

We have announced that we will incur approximately $340 million to $364 million for capital expenditures during 2004 for maintenance of production and expansion projects. We, along with other participants in the coal industry, have been informed by insurance companies that they no longer will provide surety bonds for workers’ compensation and other post employment benefits without collateral. As a result, we have satisfied these obligations by providing letters of credit or other assurances of payment. However, the issuance of letters of credit under our bank credit facilities reduces amounts that we can borrow under our bank credit facilities for other purposes, including to fund operations and capital expenditures. Cash generated by operations may not be sufficient to fund our currently planned capital expenditures and to provide the collateral necessary to meet workers’ compensation and other post employment benefits performance obligations. For these and other reasons, we may need substantial additional financing. We cannot be certain that we will be able to raise additional financing, as required, or that any financing, if available, will be on terms acceptable to us. Debt financing would increase our interest expense, reducing operating results, and could include covenants that are more restrictive than those in our current financings, including limitations on the payment of dividends and on the incurrence of additional debt. The issuance of additional equity could be dilutive to our existing stockholders. If we cannot obtain financing, it could reduce capital expenditures, particularly for expansion projects. Such a reduction in spending for these projects, however, could adversely affect future performance.

 

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We may be unable to comply with restrictions imposed by our senior credit facility which could result in a default under these agreements.

 

Our senior credit facility imposes a number of restrictions on us. A failure to comply with these restrictions could adversely affect our ability to borrow under our senior credit facility or result in an event of default under these agreements and our other debt. Our senior credit facility contains financial and other covenants that create limitations on our ability to, among other things, borrow the full amount under our senior credit facility or incur additional debt, and requires us to maintain various financial ratios and comply with various other financial covenants. These financial covenants include a funded debt ratio that requires us to maintain a ratio of total indebtedness for borrowed money as of the last day of each quarter to total earnings before interest, taxes, depreciation and amortization and excluding any extraordinary gains or losses for the four quarters ended on that date of not more than 3.5 to 1 and a ratio for the last four consecutive quarters of total earnings before interest, taxes, depreciation and amortization and excluding any extraordinary gains or losses to total interest payable (including amortization of debt discount) on indebtedness for borrowed money of not less than 4.5 to 1. A covenant also limits capital expenditures to $455 million for the fiscal year ending December 31, 2004 and $470 million for the fiscal year ending December 31, 2005. Our ability to comply with these restrictions depends upon our operating results, which recently have deteriorated from earlier periods, and we may be unable to comply with these covenants and other restrictions in our senior credit facility. In the event of a default, our lenders could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we might not be able to pay these amounts or we might be forced to seek an amendment to our debt agreements which could make the terms of these agreements more onerous for us. Failure to comply with these restrictions, even if waived by our bank lenders, also could adversely affect our credit ratings, which could increase the costs of debt financings to us and impair our ability to obtain additional debt financing.

 

Our credit ratings have recently been downgraded to a sub-investment grade rating, which could adversely affect our costs and expenses.

 

In December 2003, Standard and Poor’s classed our long-term debt as BB- (13th lowest out of 22 rating categories). The rating indicates that an obligor faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions, which could lead to the obligor’s inadequate capacity to meet its financial commitment on the obligation. The negative sign shows relative standing within the rating category. At the same time, Standard and Poor’s placed our senior unsecured debt rating on CreditWatch with negative implications.

 

In December 2003, Moody’s Investor Service classed our long-term debt as Ba3 (13th lowest out of 21 rating categories). The rating remains under review for possible further downgrade. Bonds that are rated Ba are considered to have speculative elements; their future cannot be considered as well-assured. The protection of interest and principal payments on debt rated Ba is considered moderate, and thereby not well safeguarded during both good and bad times. Uncertainty of ability to repay characterizes bonds in this class. The modifier 3 indicates that the obligation ranks in the lower end of its generic rating category.

 

The downgrading of our credit ratings could adversely affect our ability to borrow and result in more restrictive borrowing terms, including increased borrowing costs, more restrictive covenants and the extension of less open credit. This in turn could affect our operational flexibility.

 

We may not be able to maintain our competitive position because coal and gas markets are highly competitive and are affected by factors beyond our control.

 

We compete with coal producers in various regions of the United States for domestic sales, and it competes both with domestic and foreign coal producers for sales in international markets. Demand for our coal by our

 

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principal customers is affected by the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power. We sell coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.

 

A significant decline in the prices we receive for our coal and gas could adversely affect our operating results and cash flows.

 

Our results of operations are highly dependent upon the prices we receive for our coal and gas, which are closely linked to consumption patterns of the electric generation industry and certain industrial and residential patterns where gas is the principal fuel. Extended or substantial price declines for coal or gas would adversely affect our operating results for future periods and our ability to generate cash flows necessary to improve productivity and expand operations. For example, in 1998, 1999 and 2001, demand for coal decreased because of the warm winters in the northeastern United States. This resulted in increased inventories that caused pricing decreases. Natural gas prices have been volatile.

 

We may not be able to produce sufficient amounts of coal to fulfill our customers’ requirements, which could harm our customer relationships.

 

We may not be able to produce sufficient amounts of coal to meet customer demand, including amounts that we are required to deliver under long-term contracts. Our inability to satisfy our contractual obligations could result in our customers initiating claims against us. Our inability to satisfy demand could otherwise harm our relationships with our customers.

 

If the coal or gas industry experiences overcapacity in the future, our profitability could be impaired.

 

During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in added production capacity throughout the industry, all of which led to increased competition and lower coal prices. Increases in coal prices similarly could encourage the development of expanded capacity by new or existing coal producers. Any overcapacity could reduce coal prices in the future. Increased prices for gas typically stimulate additional exploration and often result in additional supplies brought to market. Increased gas supply could reduce gas prices in the future.

 

If customers do not extend existing contracts or enter into new long-term contracts for coal, the stability and profitability of our operations could be affected.

 

During the twelve months ended December 31, 2003, approximately 95% of the coal we produced was sold under contracts with terms of one year or more. If a substantial portion of our long-term contracts are modified or terminated, we would be adversely affected if we are unable to replace them or if our new contracts were not at the same level of profitability. The profitability of our long-term coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, and includes our production costs and other factors. Price changes, if any, provided in long-term supply contracts are not intended to reflect our cost increases, and therefore increases in our costs may reduce our profit margins. In addition, in periods of declining market prices, provisions for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility. As a result, we may not be able to obtain long-term agreements at favorable prices (compared to either market conditions, as they may change from time to time, or our cost structure) and long-term contracts may not contribute to our profitability.

 

We depend on two customers for a significant portion of our revenues and the loss of either one of these customers could adversely affect us.

 

During the twelve months ended December 31, 2003, two customers accounted for approximately 21% of our total revenue and one customer, Allegheny Energy, alone accounted for approximately 14% of our total

 

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revenue. Our business and operating results could be adversely affected if either one of these customers does not continue to purchase the same amount of coal or gas as it has purchased from us in the past or on terms, including pricing, it has under existing agreements.

 

Some of our long-term contracts require us to supply all of our customers’ coal needs. If these customers’ coal requirements decline, our operating results may be adversely affected.

 

We have requirements contracts with certain customers which require us to supply all of those customers’ coal needs but allow the customers to defer or vary the amount of coal that they accept. For example, during 2002, the reduction in the amount required by certain of these customers contributed to the reduction in our earnings when we could not find alternative customers at the same price and volume levels. If these or other customers with requirements contracts need less coal in the future, it could adversely affect our operating results.

 

The creditworthiness of our customer base has declined.

 

Our ability to receive payment for coal or gas sold depends on the creditworthiness of our customers. In general, the creditworthiness of our customers has declined. If this trend were to continue, the number of customers with acceptable credit profiles could decline. The bankruptcy of a customer could result in a loss of revenue for coal or gas already shipped, or in adverse changes to our sales contracts being imposed by the courts.

 

We may not be able to accomplish acquisitions effectively, which requires us to outbid competitors, obtain financing on acceptable terms and integrate acquired operations.

 

The energy industry is a rapidly consolidating industry, with many companies seeking to consummate acquisitions and increase their market share. In this environment, we compete and will continue to compete with many other buyers for acquisitions. Some of those competitors may be able to outbid us for acquisitions because they have greater financial resources. As a result of these and other factors, future acquisitions may not be available to us on attractive terms. Our ability to consummate any acquisition will be subject to various conditions, including the negotiation of satisfactory agreements and obtaining necessary regulatory approvals and financing. Once any acquisition is completed, we may not be able to achieve expected operating benefits through cost reductions, increased efficiency and integration with our existing operations. As a result, our operating results may be adversely affected.

 

Disputes with our customers concerning contracts can result in litigation, which could result in our paying substantial damages or incurring loss of revenues.

 

From time to time, we have disputes with our customers over the provisions of long-term contracts relating to, among other things, coal quality, pricing and quantity. We may not be able to resolve any future disputes in a satisfactory manner, which could result in us paying substantial damages or suffering reduced revenues.

 

Coal mining is subject to conditions or events beyond our control, which could cause our quarterly or annual results to deteriorate.

 

Our coal mining operations are predominantly underground mines. These mines are subject to conditions or events beyond our control that could disrupt operations, affect production and the cost of mining at particular mines for varying lengths of time and have a significant impact on our operating results. These conditions or events have included:

 

  variations in thickness of the layer, or seam, of coal;

 

  amounts of rock and other natural materials intruding into the coal seam and other geological conditions;

 

  equipment failures or repair;

 

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  fires and other accidents; and

 

  weather conditions.

 

We face numerous uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

 

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. None of our coal reserve estimates has been reviewed by independent experts.

 

Some of the factors and assumptions which impact economically recoverable reserve estimates include:

 

  geological conditions;

 

  historical production from the area compared with production from other producing areas;

 

  the assumed effects of regulations and taxes by governmental agencies;

 

  assumptions governing future prices; and

 

  future operating costs.

 

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual reserves.

 

The exploration for, and production of, gas is an uncertain process with many risks.

 

The exploration for and production of gas involves numerous risks. The cost of drilling, completing and operating wells for coalbed methane or other gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:

 

  unexpected drilling conditions;

 

  pressure or irregularities in formations;

 

  equipment failures or repairs;

 

  fires or other accidents;

 

  adverse weather conditions;

 

  pipeline ruptures or spills; and

 

  shortages or delays in the availability of drilling rigs and the delivery of equipment.

 

Our future drilling activities may not be successful, and we cannot be sure that our drilling success rates will not decline. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Also, we may not be able to obtain any options or lease rights in potential drilling locations that we identify which, among other things, could prevent us from producing gas at potential drilling locations.

 

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The coal beds from which we produce methane gas frequently contain water which may hamper our ability to produce gas in commercial quantities.

 

The amount of coalbed methane that can be commercially produced depends upon the coal quality, the original gas content of the coal seam, the thickness of the seam, the reservoir pressure, the rate at which gas is released from the coal, and the existence of any natural fractures through which the gas can flow to the well bore. However, coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce gas in commercial quantities.

 

Disruption of rail, barge and other systems which deliver our coal, or of pipeline systems which deliver our gas, or increase in transportation costs could make our coal or gas less competitive.

 

Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to provide access to markets. Disruption of transportation services because of weather-related problems, strikes, lock-outs or other events could temporarily impair our ability to supply coal to customers and adversely affect our profitability. Transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make our coal less competitive.

 

The marketability of our gas production partly depends on the availability, proximity and capacity of pipeline systems owned by third parties. Unexpected changes in access to pipelines could adversely affect our operations.

 

Government laws, regulations and other legal requirements relating to protection of the environment and health and safety matters increase our costs of doing business and may restrict our operations.

 

We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign, authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed and control of surface subsidence from underground mining. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitive position. In addition, we could incur substantial costs, including clean up costs, fines and civil or criminal sanctions and third party damage claims for personal injury, property damage, wrongful death, or exposure to hazardous substances, as a result of violations of or liabilities under environmental laws.

 

For example, we incur and will continue to incur significant costs associated with the investigation and remediation of environmental contamination under the federal Comprehensive Environmental Response, Compensation and Liability Act (Superfund) and similar state statutes and has been named as a potentially responsible party at Superfund sites in the past. Our costs for these matters, which currently relate predominantly to one site, could exceed our current accruals, which were $2.7 million at December 31, 2003. To date, we have spent $2.3 million for remediation of this waste disposal site and related expenses. The discovery of additional contaminants or the imposition of additional clean-up obligations or other liabilities could result in substantially greater costs than we have estimated.

 

We must obtain governmental permits and approvals for mining operations, which can be a costly and time consuming process and result in restrictions on our operations.

 

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the

 

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commencement or continuation of exploration or production operations. For example, we often are required to prepare and present to federal, state and local authorities data pertaining to the effect or impact that proposed exploration for or production of coal may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements which restrict our ability to conduct our mining operations or to do so profitably.

 

The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion. As a result, they may switch to other fuels, which would affect the volume of our sales.

 

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulations of emissions from coal-fired electric generating plants could increase the costs of using coal thereby reducing demand for coal as a fuel source, the volume of our coal sales and price. Stricter regulations could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future.

 

For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users may need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), blend high sulfur coal with low sulfur coal or switch to other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which power generators switch to low-sulfur fuel could materially affect us if we cannot offset the cost of sulfur removal by lowering the delivered costs of our higher sulfur coals on an energy equivalent basis.

 

Other new and proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases may require the installation of additional costly control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels. For example, the Environmental Protection Agency recently proposed separate regulations to establish mercury emission limits nationwide and to reduce the interstate transport of fine particulate matter and ozone through reductions in sulfur dioxides and nitrogen oxides through the eastern United States. The Environmental Protection Agency continues to require reduction of nitrogen oxide emissions in 22 eastern states and the District of Columbia and will require reduction of particulate matter emissions over the next several years for areas that do not meet air quality standards for fine particulates. In addition, Congress and several states are now considering legislation to further control air emissions of multiple pollutants from electric generating facilities and other large emitters. These new and proposed reductions will make it more costly to operate coal-fired plants and could make coal a less attractive fuel alternative to the planning and building of utility power plants in the future. To the extent that any new or proposed requirements affect our customers, this could adversely affect our operations and results.

 

We have significant reclamation and mine closure obligations. If the assumptions underlying our accruals are materially inaccurate, we could be required to expend greater amounts than anticipated.

 

The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. We accrue for the costs of current mine disturbance and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation and mine-closing liabilities, which are based upon permit requirements and our experience, were $383 million at December 31, 2003. On January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143 (SFAS 143) to account for the costs related to the closure of mines and gas wells

 

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and the reclamation of the land upon exhaustion of coal and gas reserves. This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. As a result of this change in accounting principle, we recognized a gain of $5 million, net of a tax cost of $3 million. At the time of adoption, total assets, net of accumulated depreciation, increased approximately $59 million, and total liabilities increased approximately $51 million. These amounts recorded upon adoption are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected.

 

Federal, state and local authorities extensively regulate our gas production activities.

 

The gas industry is subject to extensive legislation and regulation, which is under constant review for amendment or expansion. Any changes may affect, among other things, the pricing or marketing of gas production. State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing and well site restoration. If we fail to comply with statutes and regulations, we may be subject to substantial penalties, which would decrease our profitability.

 

Deregulation of the electric utility industry could have unanticipated effects on our industry.

 

Deregulation of the electric utility industry will enable purchasers of electricity to shop for the lowest cost suppliers. If our electric power generator customers become more sensitive to long-term price or quantity commitments in a more competitive environment, it may be more difficult for us to enter into long-term contracts and could subject our revenue stream to increased volatility which may adversely affect our profitability. Deregulation of the power industry may have other consequences for our industry, such as efforts to reduce coal prices, which may have a negative effect on our operating results.

 

The passage of legislation responsive to the Framework Convention on Global Climate Change or similar governmental initiatives could result in restrictions on coal use.

 

The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change which is intended to limit or capture emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a potentially binding set of emissions targets for developed nations. Although the specific emissions targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. If the Kyoto Protocol or other comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States, it could have the effect of restricting the use of coal. Other efforts to reduce emissions of greenhouse gases and federal initiatives to encourage the use of natural gas also may affect the use of coal as an energy source.

 

We are subject to the federal Clean Water Act and similar state laws which impose treatment, monitoring and reporting obligations.

 

The federal Clean Water Act and corresponding state laws affect coal mining operations by imposing restrictions on discharges into regulated waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. New requirements under the Clean Water Act and corresponding state laws could cause us to incur significant additional costs that adversely affect our operating results.

 

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We have significant obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, could result in us being required to expend greater amounts than anticipated.

 

We provide various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. At December 31, 2003, the current and non-current portions of these obligations included:

 

  post retirement medical and life insurance ($1.6 billion);

 

  coal workers’ black lung benefits ($456 million); and

 

  workers’ compensation ($316 million).

 

However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. These obligations are unfunded, except for coal workers’ black lung benefits, of which approximately 1% was funded at December 31, 2003. In addition, several states in which we operate consider changes in workers’ compensation laws from time to time. Such changes, if enacted, could increase our benefit expense.

 

If lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan exceed the total of the service cost and the interest cost in a plan year, we would need to make an adjustment to operating results equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum payment in that year, which may result in an adjustment that could materially reduce operating results.

 

Our defined benefit pension plan for salaried employees allows such employees to elect to receive a lump-sum distribution in lieu of annual payments when they retire from CONSOL Energy. Statement of Financial Accounting Standards No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Terminations Benefits”, requires that if the lump-sum distributions made for a plan year, which for us is October 1 to September 30, exceed the total of the service cost and interest cost for the plan year, we would need to recognize for that year’s results of operations an adjustment equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum in that year. If lump sum payments exceed the total of the service cost and the interest cost, the adjustment could materially reduce operating results.

 

New regulations have expanded the definition of black lung disease and generally made it easier for claimants to assert and prosecute claims, which could increase our exposure to black lung benefit liabilities.

 

In January 2001, the United States Department of Labor amended the regulations implementing the federal black lung laws to give greater weight to the opinion of a claimant’s treating physician, expand the definition of black lung disease and limit the amount of medical evidence that can be submitted by claimants and respondents. The amendments also alter administrative procedures for the adjudication of claims, which, according to the Department of Labor, results in streamlined procedures that are less formal, less adversarial and easier for participants to understand. These and other changes to the federal black lung regulations could significantly increase our exposure to black lung benefits liabilities.

 

In recent years, legislation on black lung reform has been introduced but not enacted in Congress. It is possible that this legislation will be reintroduced for consideration by Congress. If any of the proposals included in this or similar legislation is passed, the number of claimants who are awarded benefits could significantly increase. Any such changes in black lung legislation, if approved, may adversely affect our business, financial condition and results of operations.

 

Fairmont Supply Company, our subsidiary, is a co-defendant in various asbestos litigation cases which could result in making payments in the future that are material.

 

One of our subsidiaries, Fairmont Supply Company, which distributes industrial supplies, currently is named as a defendant in approximately 22,600 asbestos claims in state courts in Pennsylvania, Ohio, West

 

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Virginia, Maryland, New Jersey and Mississippi. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time and, in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. To date, payments by Fairmont with respect to asbestos cases have not been material. However, payments in the future with respect to pending or future asbestos cases could be material to our financial position, results of operations or cash flows.

 

We have been informed by insurance companies that, unless provided with collateral, they no longer will issue surety bonds that we and other coal mining companies are required by law to obtain.

 

Various federal or state laws and regulations require us to obtain surety bonds or to provide other assurance of payment for certain of our long-term liabilities including mine closure or reclamation costs, workers’ compensation and other post employment benefits. We, along with other participants in the coal industry, have been informed by insurance companies that they no longer will provide surety bonds for workers’ compensation and other post employment benefits without collateral. We have satisfied our obligations under these statutes and regulations by providing letters of credit or other assurances of payment. However, letters of credit can be significantly more costly to us than surety bonds. The issuance of letters of credit under our bank credit facilities also reduces amounts that we can borrow under our bank credit facilities for other purposes.

 

We and certain of our officers are defendants in one or more purported class action lawsuits alleging the defendants issued false and misleading statements to the public that could result in our making substantial payments.

 

On October 21, 2003, a complaint was filed in the United States District Court for the Western District of Pennsylvania on behalf of Seth Moorhead against us, J. Brett Harvey and William J. Lyons. The complaint alleges, among other things, that the defendants violated Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated under the Exchange Act and that during the period between January 24, 2002 and July 18, 2002 the defendants issued false and misleading statements to the public that failed to disclose or misrepresented the following, among other things that: (a) we utilized an aggressive approach regarding our spot market sales by reserving 20% of our production to that market, and that by increasing our exposure to the spot market, we were subjecting ourself to increased risk and uncertainty as the price and demand for coal could be volatile; (b) we were experiencing difficulty selling the production that we had allocated to the spot market, and, nonetheless, we maintained our production levels which caused our coal inventory to increase; (c) our increasing coal inventory was causing our expenses to rise dramatically, thereby weakening our financial condition; and (d) based on the foregoing, defendants’ positive statements regarding our earnings and prospects were lacking in a reasonable basis at all times and therefore were materially false and misleading. The complaint asks the court to (1) award unspecified damages to plaintiff and (2) award plaintiff reasonable costs and expenses incurred in connection with this action, including counsel fees and expert fees. Two other class action complaints have purportedly been filed in the United States District Court for the Western District of Pennsylvania against us and certain officers and directors. We have not yet been served with either purported complaint. If we are not successful in defending one or more of these lawsuits we may have to make substantial payments to the plaintiffs.

 

Our rights plan may have anti-takeover effects that could prevent a change of control.

 

On December 19, 2003, we adopted a rights plan which, in certain circumstances, including a person or group acquiring, or the commencement of a tender or exchange offer that would result in a person or group acquiring, beneficial ownership of more than 15% of the outstanding shares of our common stock, would entitle

 

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each right holder to receive, upon exercise of the right, shares of our common stock having a value equal to twice the right exercise price. For example, at an exercise price of $80 per right, each right not otherwise voided would entitle our holders to purchase $160 worth of shares of our common stock for $80. Assuming that shares of our common stock had a per share value of $16 at such time, the holder of each right would be entitled to purchase ten shares of our common stock for $80, or a price of $8 per share, one half its then market price. This and other provisions of our rights plan could make it more difficult for a third party to acquire us, which could hinder stockholders’ ability to receive a premium for our stock over the prevailing market prices.

 

Our share price may decline due to shares eligible for future sale.

 

A total of 52,374,425 shares of our common stock recently have been registered for resale by stockholders who purchased the shares in private placements in September and October 2003 by us and our former principal stockholder RWE Rheinbraun. This amount, together with the 16,622,932 shares that are registered by this registration statement, substantially exceeds the approximately 22 million shares held by stockholders other than RWE before September 23, 2003, the date that it initially sold shares in a private offering. Therefore, the number of shares potentially available for trading in the public markets has significantly increased since September 23, 2003. We cannot predict the effect, if any, that future sales of shares of our common stock, or the availability of such shares for sale, would have on the market price prevailing from time to time. Sales by holders of substantial amounts of our common stock in the public market, or the perception that such sales could occur, could adversely affect prevailing market prices for our common stock. A reduction in the market price of our common stock could impair our ability to raise additional capital through future public offerings of our equity securities.

 

We are a holding company and conduct substantially all of our operations through subsidiaries. Our ability to service our debt and pay dividends to holders of our common stock will depend upon our receiving distributions or similar payments from our subsidiaries.

 

Because substantially all of our operations are conducted through subsidiaries, our cash flow and, therefore, our ability to service our debt and pay dividends to holders of our common stock primarily depends upon the earnings of our subsidiaries and the distribution of those earnings to, or upon loans or other payments of funds by those subsidiaries to, us. Our subsidiaries are separate and distinct legal entities and have no obligation to pay any amounts due pursuant to our debt securities or to make any funds available to us for the payment of dividends or otherwise. In addition, the payment of dividends and the making of loans and advances to us by our subsidiaries may be subject to statutory or contractual restrictions, will be contingent upon the earnings of our subsidiaries and subject to various business considerations.

 

We may not continue to pay dividends.

 

The declaration and payment of dividends by us is subject to the discretion of our board of directors and is under their continuing review. The payment of dividends may be limited by the terms of additional financing. We may not pay dividends in the future.

 

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FORWARD-LOOKING STATEMENTS

 

Some statements in this prospectus or any prospectus supplement, and the documents incorporated by reference in this prospectus or any prospectus supplement are known as “forward-looking statements,” as that term is used in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements may relate to, among other things, future performance generally, business development activities, future capital expenditures, financing sources and availability and the effects of regulation and competition.

 

When we use the words “believe,” “intend,” “expect,” “may,” “will,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements.

 

We warn you that forward-looking statements are only predictions. Actual events or results may differ as a result of risks that we face, including those set forth in the sections of this prospectus called “Risk Factors.” Those are representative of factors that could affect the outcome of the forward-looking statements. These and the other factors discussed elsewhere in this prospectus or any prospectus supplement and the documents incorporated by reference in them are not necessarily all of the important factors that could cause our results to differ materially from those expressed in our forward-looking statements. Forward-looking statements speak only as of the date they are made and we undertake no obligation to update them.

 

USE OF PROCEEDS

 

We will not receive any of the proceeds from the sale of the common stock described in this prospectus.

 

MARKET FOR COMMON STOCK

 

Our common stock is listed on the New York Stock Exchange under the symbol CNX. The following table sets forth for the periods indicated the range of high and low sales prices per share of our common stock as reported on the New York Stock Exchange and the cash dividends declared on the common stock for the periods indicated.

 

     High

   Low

   Dividends

Twelve Month Period Ended December 31, 2002

              

Quarter Ended March 31, 2002

   27.49    21.19    .28

Quarter Ended June 30, 2002

   28.32    21.25    .14

Quarter Ended September 30, 2002

   21.54    9.80    .14

Quarter Ended December 31, 2002

   17.90    10.65    .14

Twelve Month Period Ended December 31, 2003

              

Quarter Ended March 31, 2003

   18.01    14.55    .14

Quarter Ended June 30, 2003

   24.61    15.65    .14

Quarter Ended September 30, 2003

   22.95    18.18    .14

Quarter Ended December 31, 2003

   26.80    18.67    .14

 

On February 13, 2004, there were approximately 13,800 holders of record of our common stock. The computation of the approximate number of shareholders is based upon a broker search.

 

The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s board of directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s board of directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, the credit ratings of CONSOL Energy, planned investments by CONSOL Energy and such other factors as the board of directors deems relevant. CONSOL Energy’s credit facilities prohibit the payment of cash dividends on the common stock in excess of $0.56 per share in any fiscal year.

 

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SELECTED FINANCIAL DATA

 

The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the twelve months ended December 31, 2003, December 31, 2002, June 30, 2001 and June 30, 2000, and the six months ended December 31, 2001 and June 30, 1999 are derived from our audited consolidated financial statements. The selected consolidated financial data for, and as of the end of, the twelve months ended December 31, 2001 and the six months ended December 31, 2000, are derived from our unaudited consolidated financial statements, and in the opinion of management include all adjustments, consisting only of normal recurring accruals, that are necessary for a fair presentation of our financial position and operating results for these periods. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and the financial statements and related notes included in this report. In 1999, we changed our fiscal year from a calendar year to a fiscal year ended June 30. In 2001, we changed our fiscal year from a fiscal year ended June 30 to a fiscal year ended December 31 in order to coordinate reporting periods with our majority shareholder at that time commencing with the fiscal year beginning January 1, 2002.

 

Statement Of Income Data   Twelve Months Ended December 31,

   

Six Months Ended

December 31,


 

Twelve Months

Ended June 30,


   

Six Months

Ended June 30,


(In thousands except per share
data)
  2003

    2002

    2001

    2001

    2000

  2001

    2000

    1999

Revenue:

                                                           

Sales (A)

  $ 2,042,851     $ 2,003,345     $ 2,095,463     $ 964,460     $ 992,201   $ 2,123,202     $ 2,094,850     $ 1,081,922

Freight (A)

    114,582       134,416       159,029       70,314       72,225     160,940       165,934       80,487

Other income

    65,033       45,837       64,526       31,223       37,154     70,457       64,359       28,560
   


 


 


 


 

 


 


 

Total Revenue

    2,222,466       2,183,598       2,319,018       1,065,997       1,101,580     2,354,599       2,325,143       1,190,969

Costs:

                                                           

Cost of goods sold and other operating charges

    1,624,016       1,543,189       1,585,686       761,146       730,329     1,554,867       1,498,982       790,119

Freight expense

    114,582       134,416       159,029       70,314       72,225     160,940       165,934       80,487

Selling, general and administrative expense

    77,571       65,888       61,155       31,493       33,381     63,043       62,164       30,218

Depreciation, depletion and amortization

    242,152       262,873       243,588       120,039       119,723     243,272       249,877       121,237

Interest expense

    34,451       46,213       43,356       16,564       30,806     57,598       55,289       30,504

Taxes other than income

    160,209       172,479       160,954       80,659       77,771     158,066       174,272       98,244

Export sales excise tax resolution

    (614 )     (1,037 )     (118,120 )     5,402       —       (123,522 )     —         —  

Restructuring costs

    3,606       —         —         —         —       —         12,078       —  
   


 


 


 


 

 


 


 

Total Costs

    2,255,973       2,224,021       2,135,648       1,085,617       1,064,235     2,114,264       2,218,596       1,150,809
   


 


 


 


 

 


 


 

Earnings (Loss) before income taxes

    (33,507 )     (40,423 )     183,370       (19,620 )     37,345     240,335       106,547       40,160

Income taxes (benefits)

    (20,941 )     (52,099 )     32,164       (20,679 )     3,842     56,685       (493 )     121
   


 


 


 


 

 


 


 

Earnings (Loss) before Cumulative Effect of Change in Accounting Principle

    (12,566 )     11,676       151,206       1,059       33,503     183,650       107,040       40,039
   


 


 


 


 

 


 


 

Cumulative Effect of Changes in Accounting for Mine Closing, Reclamation and Gas Well Closing Costs, Net of Income Taxes of $3,035

    4,768       —         —         —         —       —         —         —  
   


 


 


 


 

 


 


 

Net Income (Loss)

  $ (7,798 )   $ 11,676     $ 151,206     $ 1,059     $ 33,503   $ 183,650     $ 107,040     $ 40,039
   


 


 


 


 

 


 


 

Earnings per share:

                                                           

Basic (B)

  $ (0.10 )   $ 0.15     $ 1.92     $ 0.01     $ 0.43   $ 2.34     $ 1.35     $ 0.62
   


 


 


 


 

 


 


 

Dilutive (B)

  $ (0.10 )   $ 0.15     $ 1.91     $ 0.01     $ 0.43   $ 2.33     $ 1.35     $ 0.62
   


 


 


 


 

 


 


 

Weighted average number of common shares outstanding:

                                                           

Basic

    81,732,589       78,728,560       78,671,821       78,699,732       78,584,204     78,613,580       79,499,576       64,784,685
   


 


 


 


 

 


 


 

Dilutive

    82,040,418       78,834,023       78,964,557       78,920,046       78,666,391     78,817,935       79,501,326       64,784,685
   


 


 


 


 

 


 


 

Dividend per share

  $ 0.56     $ 0.84     $ 1.12     $ 0.56     $ 0.56   $ 1.12     $ 1.12     $ 0.39
   


 


 


 


 

 


 


 

 

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Balance Sheet Data    At December 31,

    At June 30,

 
(In thousands)    2003

    2002

    2001

    2001

    2000

    1999

 

Working capital (deficiency)

   $ (353,759 )   $ (191,596 )   $ (70,505 )   $ (368,118 )   $ (375,074 )   $ (261,427 )

Total assets

     4,318,978       4,293,160       4,298,732       3,894,971       3,866,311       3,875,026  

Short-term debt

     68,760       204,545       77,869       360,063       464,310       345,525  

Long-term debt (including current portion)

     495,242       497,046       545,440       303,561       307,362       326,495  

Total deferred credits and other liabilities

     2,761,830       2,828,249       2,913,763       2,378,323       2,358,725       2,423,483  

Stockholders’ equity

     290,637       162,047       271,559       351,647       254,179       254,725  

 

Other Operating Data  

Twelve Months

Ended December 31,


 

Six Months

Ended December 31,


 

Twelve Months

Ended June 30,


 

Six Months

Ended June 30,


    2003

  2002

  2001

  2001

  2000

  2001

  2000

  1999

Coal:

                                               

Tons sold (in thousands) (C)(D)

    63,962     67,308     76,503     35,587     36,590     77,322     78,714     38,553

Tons produced (in
thousands) (D)

    60,388     66,230     73,705     34,355     32,508     71,858     73,073     38,244

Productivity (tons per
manday) (D)

    41.26     40.18     39.95     37.15     41.60     42.21     44.23     39.86

Average production cost ($ per ton produced) (D)

  $ 26.24   $ 24.73   $ 22.21   $ 23.73   $ 21.93   $ 21.35   $ 20.00   $ 21.47

Average sales price of tons produced ($ per ton produced) (D)

  $ 27.61   $ 26.76   $ 24.66   $ 25.02   $ 23.41   $ 23.93   $ 23.66   $ 25.12

Recoverable coal reserves (tons in millions) (D)(E)

    4,146     4,275     4,365     4,365     4,372     4,411     4,461     4,705

Number of mining complexes (at period end)

    20     22     27     27     23     23     22     24

Gas:

                                               

Net sales volume produced (in billion cubic feet) (D)

    44.46     41.30     33.92     17.61     14.18     29.75     14.20     2.67

Average sale price ($ per mcf) (D) (F)

  $ 4.31   $ 3.17   $ 4.04   $ 2.63   $ 4.73   $ 5.19   $ 3.01   $ 2.04

Average costs ($ per mcf) (D)

  $ 2.35   $ 2.18   $ 2.38   $ 2.27   $ 1.94   $ 2.16   $ 1.60   $ 2.31

Net estimated proved reserves (in billion cubic feet) (D)(G)

    1,004     961     1,023     1,023     639     677     653     409

 

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Cash Flow Statement
Data
 

Twelve Months

Ended December 31,


   

Six Months

Ended December 31,


   

Twelve Months

Ended June 30,


   

Six Months

Ended June 30,


 
(In thousands)   2003

    2002

    2001

    2001

    2000

    2001

    2000

    1999

 

Net cash provided by operating activities

  $ 381,127     $ 329,556     $ 347,356     $ 93,084     $ 181,568     $ 435,839     $ 295,028     $ 84,995  

Net cash used in investing activities

    (204,614 )     (339,936 )     (114,160 )     (11,598 )     (131,078 )     (233,321 )     (299,554 )     (100,790 )

Net cash (used in) provided by financing activities

    (181,517 )     6,315       (228,184 )     (82,529 )     (48,419 )     (194,074 )     (10,852 )     8,069  

Other Financial Data

(In thousands)

 

 

                                               

Capital expenditures

  $ 290,652     $ 295,025     $ 266,825     $ 162,700     $ 109,007     $ 213,132     $ 142,270     $ 105,032  

EBIT (H)

    (5,354 )     (1,230 )     194,330       (2,132 )     65,590       262,052       156,165       68,438  

EBITDA (H)

    236,798       261,643       437,918       117,907       185,313       505,324       406,042       189,675  

Ratio of earnings to fixed charges (I)

    —         —         4.59       —         1.85       4.54       2.70       2.19  

(A) See note 30 of notes to consolidated financial statements for sales and freight by operating segment.
(B) Basic earnings per share are computed using weighted average shares outstanding. Differences in the weighted average number of shares outstanding for purposes of computing dilutive earnings per share are due to the inclusion of the weighted average dilutive effect of employee and non-employee director stock options granted, totaling 307,829, 105,463 and 292,736 for the twelve months ended December 31, 2003, December 31, 2002 and 2001; 220,314 and 82,187 for the six months ended December 31, 2001 and 2000; and 204,335 and 1,750 for twelve months ended June 30, 2001 and 2000. There were no dilutive employee or non-employee director stock options for any of the previous periods presented.
(C) Includes sales of coal produced by CONSOL Energy and purchased from third parties. Of the tons sold, CONSOL Energy purchased the following amount from third parties; 2.5 million tons in the twelve months ended December 31, 2003, 2.5 million tons in the twelve months ended December 31, 2002, 2.8 million tons in the twelve months ended December 31, 2001, 1.3 million tons in the six months ended December 31, 2001, 1.5 million tons in the six months ended December 31, 2000, 2.7 million tons in the twelve months ended June 30, 2001, 3.5 million tons in the twelve months ended June 30, 2000, 3.9 million tons in the twelve months ended June 30, 1999 and 2.2 million tons in the six months ended June 30, 1999. Sales of coal produced by equity affiliates were; 1.0 million tons in the twelve months ended December 31, 2003, 1.6 million tons in the twelve months ended December 31, 2002, 1.6 million tons in the twelve months ended December 31, 2001, 0.9 million tons in the six months ended December 31, 2001 and 0.7 million tons in the twelve months ended June 30, 2001. No sales from equity affiliates occurred in previous periods presented.
(D)

For entities that are not wholly owned but in which CONSOL Energy owns at least 50% equity interest, includes a percentage of their net production, sales or reserves equal to CONSOL Energy’s percentage equity ownership. For coal, Glennies Creek Mine is reported as an equity affiliate for the entire December 2003 period and Line Creek was reported as an equity affiliate through February 2003. Line Creek Mine and Glennies Creek Mine are reported as equity affiliates for the December 31, 2002 period. Line Creek Mine was also reported as an equity affiliate for the December 31, 2001 and June 30, 2001 periods. No other

 

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periods have coal equity affiliates. For gas, Knox Energy makes up the equity earnings data in 2003 and 2002. Greene Energy was part of equity earnings in 2002 and 2001. Pocahontas Gas Partnership accounts for the majority of the information reported as an equity affiliate for approximately eight months in the December 31, 2001 period and for the entire year of the previous periods presented. Sales of gas produced by equity affiliates were .08 bcf in the twelve months ended December 31, 2003, .22 bcf in the twelve months ended December 31, 2002, 5.5 billion cubic feet or bcf in the twelve months ended December 31, 2001, 1.4 bcf in the six months ended December 31, 2001, and 7.7 bcf in the twelve months ended June 30, 2001.

(E) Represents proven and probable reserves at period end.
(F) Represents average net sales price before the effect of derivative transactions.
(G) Represents proved developed and undeveloped gas reserves at period end.
(H) EBIT is defined as earnings before deducting net interest expense (interest expense less interest income) and income taxes. EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although EBIT and EBITDA are not measures of performance calculated in accordance with generally accepted accounting principles, management believes that they are useful to an investor in evaluating CONSOL Energy because they are widely used in the coal industry as measures to evaluate a company’s operating performance before debt expense and cash flow. Financial covenants in our credit facility include ratios based on EBITDA. EBIT and EBITDA do not purport to represent cash generated by operating activities and should not be considered in isolation or as substitute for measures of performance in accordance with generally accepted accounting principles. In addition, because EBIT and EBITDA are not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. Management’s discretionary use of funds depicted by EBIT and EBITDA may be limited by working capital, debt service and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties. A reconcilement of EBIT and EBITDA to financial net income is as follows:

 

(In thousands)  

Twelve Months

Ended December 31,


   

Six Months

Ended December
31,


   

Twelve Months

Ended June 30,


   

Six Months

Ended June 30,


 
    2003

    2002

    2001

    2001

    2000

    2001

    2000

    1999

 

Net Income (Loss)

  $ (7,798 )   $ 11,676     $ 151,206     $ 1,059     $ 33,503     $ 183,650     $ 107,040     $ 40,039  

Add: Interest expense

    34,451       46,213       43,356       16,564       30,806       57,598       55,289       30,504  

Less: Interest income

    (5,602 )     (5,738 )     (5,990 )     (3,734 )     (2,561 )     (4,817 )     (5,671 )     (2,226 )

Less: Interest income included in export sales excise tax resolution

    (696 )     (1,282 )     (26,406 )     4,658       —         (31,064 )     —         —    

Less: Cumulative Effect of Changes in Accounting for Mine Closing, Reclamation and Gas Well Closing Costs, net of Income taxes of $3,035

    (4,768 )                                                        

Add: Income Tax Expense (Benefit)

    (20,941 )     (52,099 )     32,164       (20,679 )     3,842       56,685       (493 )     121  
   


 


 


 


 


 


 


 


Earnings (Loss) before interest and taxes (EBIT)

    (5,354 )     (1,230 )     194,330       (2,132 )     65,590       262,052       156,165       68,438  

Add: Depreciation, depletion and amortization

    242,152       262,873       243,588       120,039       119,723       243,272       249,877       121,237  
   


 


 


 


 


 


 


 


Earnings before interest, taxes and depreciation, depletion and amortization

  $ 236,798     $ 261,643     $ 437,918     $ 117,907     $ 185,313     $ 505,324     $ 406,042     $ 189,675  
   


 


 


 


 


 


 


 


 

For purposes of computing the ratio of earnings to fixed charges, earnings represent income from continuing operations before income taxes plus fixed charges. Fixed charges include (a) interest on indebtedness (whether expensed or capitalized), (b) amortization of debt discounts and premiums and capitalized expenses related to indebtedness and (c) the portion of rent expense we believe to be representative of interest. For the twelve months ended December 31, 2003 and December 31, 2002, fixed charges exceeded earnings by $24.7 million and $30.6 million, respectively. For the six months ended December 31, 2001, fixed charges exceeded earnings by $20.4 million.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATION

 

General

 

CONSOL Energy incurred a loss before income taxes and before effect of change in accounting principle of $34 million, recognized income tax benefits of $21 million and recognized a $5 million income adjustment for the effect of change in accounting for mine closing, reclamation, and gas well closing costs resulting in a net loss of $8 million for the twelve months ended December 31, 2003. CONSOL Energy incurred a loss before income taxes of $40 million and recognized income tax benefits of $52 million, resulting in net income of $12 million for the twelve months ended December 31, 2002.

 

Total coal sales for the twelve months ended December 31, 2003 were 64.0 million tons, including our portion of sales by equity affiliates, of which 61.5 million tons of sales were produced by CONSOL Energy operations, by our equity affiliates or sold from inventory of CONSOL Energy’s produced coal, including coal sold from inventories and produced by equity affiliates. This compares with total coal sales of 67.3 million tons for the twelve months ended December 31, 2002, of which 64.8 million tons were produced by CONSOL Energy operations or sold from inventory of company produced coal including coal sold from inventories and produced by equity affiliates. The decrease in tons sold primarily is related to lower CONSOL Energy coal production in the period-to-period comparison.

 

CONSOL Energy produced 60.4 million tons, including our portion of production at equity affiliates in the 2003 period compared to 66.2 million tons, including our portion of production at equity affiliates in the 2002 period. The decrease in tons produced is primarily due to the closure of the Dilworth, Humphrey and Windsor mines, where economically mineable reserves were depleted in the last quarter of 2002. The decrease was also attributable to the sale of the assets at the Cardinal River and Line Creek mines in February 2003 and the idling of the Rend Lake mine in 2002 due to market conditions. Coal inventories, including our portion of inventories at equity affiliates, were 1.4 million tons at December 31, 2003 compared to 3.0 million tons at December 31, 2002.

 

Sales of coalbed methane gas, including our share of the sales from equity affiliates were 50.0 billion gross cubic feet in the 2003 period compared to 46.6 billion gross cubic feet in the 2002 period. The increased sales volume is primarily due to higher production volumes as a result of our on going drilling program. Our average sales price for coalbed methane gas, including our portion of sales from equity affiliates, was $4.16 per thousand cubic feet in the 2003 period compared to $3.17 per thousand cubic feet in the 2002 period. The increase in average sales price was driven by concerns for levels of natural gas in storage at the beginning of the year and by concerns over intermediate-term supplies of gas in the United States.

 

In December 2003, CONSOL Energy adopted a shareholder rights plan designed to ensure that all shareholders receive fair value for their common shares in the event of a proposed takeover and to guard against the use of partial tender offers or other coercive tactics to gain control of CONSOL Energy without offering fair value to CONSOL Energy shareholders.

 

In December 2003, Standard and Poor’s lowered CONSOL Energy’s rating of our long-term debt to BB- (13th lowest out of 22 rating categories). Standard and Poor’s defines an obligation rated ‘BB’ as less vulnerable to nonpayment than other speculative issues. However, the rating indicates that an obligor faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions, which could lead to the obligor’s inadequate capacity to meet its financial commitment on the obligation. The negative sign shows relative standing within the rating category. At the same time, Standard and Poor’s placed CONSOL Energy’s senior unsecured debt rating on CreditWatch with negative implications.

 

In December 2003, Moody’s Investor Service lowered its rating of CONSOL Energy’s long-term debt from Ba1 to Ba3 (13th lowest out of 21 rating categories). The rating remains under review for possible further downgrade. Bonds which are rated “Ba” are considered to have speculative elements; their future cannot be

 

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considered as well-assured. Often the protection of interest and principal payments may be very moderate, and thereby not well safeguarded during both good and bad times over the future. Uncertainty of position characterizes bonds in this class. The modifier 3 indicates that the obligation ranks in the lower end of its generic rating category.

 

A security rating is not a recommendation by a rating agency to buy, sell or hold securities. The security rating may be subject to change.

 

In January, 2004, CONSOL Energy announced that it intended to sell the stock in its wholly owned subsidiary CNX Australia Pty Limited to certain affiliates of AMCI, Inc. for $27.5 million, the assumption of approximately $21 million of debt, and associated interest rate swaps and foreign currency hedges. CNX Australia Pty Limited, through its wholly owned subsidiary CONSOL Energy Australia Pty Limited, owns a 50% interest in the Glennies Creek Mine in New South Wales, Australia with its joint venture partner Maitland Main Collieries Pty Limited, an affiliate of AMCI, Inc. Agreements were finalized on February 25, 2004 and are expected to result in a pre-tax gain of approximately $13 million.

 

In January 2004, a Special Committee of the Board of Directors of CONSOL Energy completed its investigation of allegations against certain directors and officers of CONSOL Energy contained in an anonymous letter sent to the United States Securities and Exchange Commission. The Special Committee found no evidence of fraud or malfeasance and no evidence to suggest that CONSOL Energy’s publicly issued financial statements were incorrect.

 

In January 2004, CONSOL Energy’s Board of Directors elected three new independent members to the Board. They were: William E. Davis, a power industry executive; William P. Powell, an investment banker; and Joseph T. Williams, a former oil and gas industry executive.

 

In February 2004, CONSOL Energy’s former majority shareholder, RWE AG, closed on a previously announced private placement sale of its remaining 16.6 million shares of CONSOL Energy common stock. On September 23 and 24, 2003, RWE closed on a previously announced sale of 14.1 million shares of CONSOL Energy common stock. On the same dates, CONSOL Energy closed on a previously announced sale of 11.0 million primary shares of its common stock, increasing the total shares of common stock outstanding to 89.9 million and reduced RWE’s initial majority interest from 73.6% to 48.9%. On October 9, 2003, RWE closed on the sale of 27.3 million shares of CONSOL Energy common stock. That sale reduced RWE’s ownership to 16.6 million shares, or 18.5%.

 

In February 2004, as a result of the sale of the remaining shares of CONSOL Energy common stock held by RWE AG and pursuant to the terms of the Placement Agreement, dated September 18, 2003, by and among CONSOL Energy, Friedman, Billings, Ramsey & Co., Inc. and RWE Rheinbraun AG, the remaining two directors representing RWE AG, Berthold Bonekamp and Dr. Rolf Zimmerman, resigned from the CONSOL Energy Board of Directors. Also in February 2004, Raj Gupta, a former oil and gas industry executive, was elected to the board of directors of CONSOL Energy. He will serve until the next election of directors at the annual meeting of shareholders.

 

Change in Fiscal Year

 

CONSOL Energy changed its fiscal year from a fiscal year ending June 30 to a calendar year ending December 31. CONSOL Energy had a transitional fiscal period ending December 31, 2001. CONSOL Energy’s first full fiscal year ending December 31 was the year that started January 1, 2002 and ended December 31, 2002. CONSOL Energy undertook this change in order to align its fiscal year with that of RWE AG, its majority shareholder at that time.

 

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Table of Contents

Results of Operations

 

Twelve Months Ended December 31, 2003 compared with Twelve Months Ended December 31, 2002 (All dollar amounts in charts reported in millions)

 

Net Income

 

Net income changed primarily due to the following items:

 

    

2003

Period


   

2002

Period


   

Dollar

Variance


   

Percentage

Change


 

Gas Sales

   $ 208     $ 147     $ 61     41.5 %

Coal Sales - Produced and Purchased

     1,758       1,777       (19 )   (1.1 )%

Other Sales and Other Income

     256       260       (4 )   (1.5 )%
    


 


 


     

Total Revenue

     2,222       2,184       38     1.7 %

Coal Cost of Goods Sold - Produced and Purchased

     1,310       1,277       33     2.6 %

Gas Cost of Goods Sold

     84       65       19     29.2 %

Other Cost of Goods Sold

     230       201       29     14.4 %
    


 


 


     

Total Cost of Goods Sold

     1,624       1,543       81     5.2 %

Depreciation, Depletion and Amortization

     242       263       (21 )   (8.0 )%

Interest Expense

     34       46       (12 )   (26.1 )%

Other

     356       372       (16 )   (4.3 )%
    


 


 


     

Total Costs

     2,256       2,224       32     1.4 %
    


 


 


 

Earnings (Loss) before Income Taxes

     (34 )     (40 )     6     15.0 %

Income Taxes

     21       52       (31 )   (59.6 )%
    


 


 


     

Earnings (Loss) Before Cumulative Effect of Change in Accounting

     (13 )     12       (25 )   (208.3 )%

Cumulative Effect of Change in Accounting Principle

     5       —         5     100.0 %
    


 


 


     

Net Income (Loss)

   $ (8 )   $ 12     $ (20 )   (166.7 )%
    


 


 


     

 

Net income (loss) for the 2003 period was lower than the 2002 period primarily due to increased cost of goods sold and lower income tax benefits, offset, in part, by higher revenues and lower depreciation, depletion and amortization. The increase in cost of goods sold was mainly attributable to higher retiree medical costs and salaried pension expenses, increased gas volumes and royalty costs related to gas sales, and costs related to mine fires at the Loveridge Mine and Mine 84. Tax benefits were lower in the 2003 period primarily due to the tax effect of the current year’s sale of our Canadian assets. The higher sales revenues are primarily attributable to the increased gas volumes sold in the 2003 period compared to the 2002 period. Depreciation, depletion and amortization expense declined primarily as a result of the equipment at the Dilworth mine and the related preparation plant becoming fully depreciated prior to the 2003 period, coinciding with the closure of the mine due to economically depleted reserves.

 

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Table of Contents

Revenue

 

    

2003

Period


  

2002

Period


  

Dollar

Variance


   

Percentage

Change


 

Sales

                            

Produced Coal

   $ 1,683    $ 1,693    $ (10 )   (0.6 )%

Produced Coal—Related Party

     1      1      —          
    

  

  


     

Total Produced Coal

     1,684      1,694      (10 )   (0.6 )%

Purchased Coal

     74      83      (9 )   (10.8 )%

Gas

     208      147      61     41.5 %

Industrial Supplies

     63      64      (1 )   (1.6 )%

Other

     14      15      (1 )   (6.7 )%
    

  

  


     

Total Sales

     2,043      2,003      40     2.0 %

Freight Revenue

     114      134      (20 )      

Freight Revenue—Related Party

     1      1      —          
    

  

  


     

Total Freight Revenue

     115      135      (20 )   (14.8 )%

Other Income

     64      46      18     39.1 %
    

  

  


     

Total Revenue and Other Income

   $ 2,222    $ 2,184    $ 38     1.7 %
    

  

  


     

 

The decrease in our produced coal sales revenue was due mainly to the reduction in volumes sold during the 2003 period substantially offset by increased average sales price per ton.

 

    

2003

Period


  

2002

Period


   Variance

   

Percentage

Change


 

Produced tons sold (in millions)

     60.9      63.2      (2.3 )   (3.6 )%

Average sales price per ton

   $ 27.67    $ 26.80    $ 0.87     3.2 %

 

The decrease in tons sold is related to the closure of the Dilworth, Humphrey and Windsor mines, where economically mineable reserves were depleted in the last quarter of 2002. The decrease in tons sold was also attributable to the sale of the assets at the Cardinal River Mine in February 2003 and the idling of the Rend Lake mine in 2002 due to market conditions. Expected coal production in the fourth quarter of 2003 was also impacted by unfavorable mining conditions at Enlow Fork Mine, Mill Creek Mine and Mine 84, a roof fall along the west beltline at the Bailey Mine, equipment problems at VP #8 and Jones Fork Mines and flooding along the Ohio River. These decreases in tonnage were offset, in part, by increased sales of our produced coal primarily at the McElroy Mine and, to a lesser extent, at several other mines. The increased tonnage at the McElroy Mine is attributable to the mine running for the full 2003 year compared to being idled for two months of the 2002 year. The McElroy Mine increase is also attributable to the preparation plant expansion that was completed in the last quarter of 2002. The reductions in our produced coal sales revenue were substantially offset by the increase in average sales price per ton sold. The increase in average sales price primarily reflects higher prices negotiated in the second half of 2002.

 

The decrease in our purchased coal sales revenue was due mainly to a decrease in average sales price per ton of purchased coal.

 

    

2003

Period


  

2002

Period


   Variance

   

Percentage

Change


 

Purchased tons sold (in millions)

     2.4      2.5      (0.1 )   (4.0 )%

Average sales price per ton

   $ 31.16    $ 33.49    $ (2.33 )   (7.0 )%

 

The reduced average sales price is primarily due to sales of purchased coal in 2003 at prices under commitments made during periods of lower prices as compared to 2002 sales of coal purchased under

 

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commitments made during a period of higher prices. The reduced sales price is also due to CONSOL Energy purchasing and selling a lower quality coal in the 2003 period compared to the 2002 period.

 

The increase in gas sales revenue was primarily due to a higher average sales price per thousand cubic feet and increased volumes sold in the 2003 period compared to the 2002 period.

 

    

2003

Period


  

2002

Period


   Variance

  

Percentage

Change


 

Gas sales volumes (in billion gross cubic feet)

     50.0      46.4      3.6    7.8 %

Average sales price per thousand cubic feet (including effects of derivative transactions)

   $ 4.16    $ 3.17    $ 0.99    31.2 %

 

The 2003 gas market price increases were largely driven by the overall supply/demand imbalance that depleted United States storage levels by the end of March 2003 and the subsequent need to refill that storage prior to the start of the next winter heating season. CONSOL Energy enters into various physical gas supply transactions with our gas marketers, selling gas under short-term multi-month contract nominations generally not exceeding one year. CONSOL Energy has also entered into eight float-for-fixed gas swap transactions and two float-for-collar gas swap transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. In 2003, these cash flow hedges represented 11% of our total 2003 produced sales volumes at an average price of $4.10 per thousand cubic feet. These cash flow hedges are expected to represent 24% of our estimated 2004 produced sales volumes at an average price of $5.17 per thousand cubic feet. CONSOL Energy sold 90% of its gas sales volumes in the 2003 period at an average price of $3.99 per thousand cubic feet compared to 77% of its gas sales volumes in the 2002 period at $3.16 per thousand cubic feet under contracts agreed to in prior periods. Higher sales volumes were a result of wells coming on line from the ongoing drilling program, which allowed CONSOL Energy to take advantage of increased demand.

 

The decrease in revenues from the sale of industrial supplies was due to reduced sales volumes.

 

Freight revenue, outside and related party, is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred.

 

Other income consists of interest income, gain or loss on the disposition of assets, equity in earnings of affiliates, service income, royalty income, derivative gains and losses, rental income and miscellaneous income.

 

    

2003

Period


   

2002

Period


   

Dollar

Variance


   

Percentage

Change


 

Gain on sale of assets

   $ 23     $ 13     $ 10     76.9 %

Royalty income

     16       12       4     33.3 %

Equity in loss of affiliates

     (9 )     (10 )     1     10.0 %

Foreign currency derivative

     5       —         5     100.0 %

Harbor maintenance fee refund

     3       —         3     100.0 %

Contract settlement

     —         7       (7 )   (100.0 )%

Other miscellaneous

     26       24       2     8.3 %
    


 


 


 

Total other revenue

   $ 64     $ 46     $ 18     39.1 %
    


 


 


 

 

The increase in gain on sale of assets primarily was related to the expiration in the 2003 period of an option granted to a third party to purchase property for which CONSOL Energy received nonrefundable proceeds of $5 million and gains from the sale of surplus equipment.

 

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Table of Contents

Royalty income increased due primarily to third parties producing more tonnage from CONSOL owned property in the period-to-period comparison.

 

The decrease in equity losses of affiliates is due mainly to the absence of $4 million in losses incurred in 2002 attributable to a coal equity affiliate, Line Creek Mine, that was sold in February 2003. The decrease is also attributable to an equity affiliate’s sale of property in the 2003 period that resulted in a gain of which our portion was approximately $2 million. These changes were offset, in part by $5 million of additional losses in the 2003 period due to a coal equity affiliate’s, Glennies Creek Mine, coal recovery rate being lower due to a rock intrusion in the coal seam.

 

Foreign currency derivative gains are related to the foreign currency hedge contracts entered into on July 10, 2002 to permit CONSOL Energy Australia Pty (CEA) to purchase Australian dollars at a fixed exchange rate. CEA entered into these hedges in order to minimize exposure to foreign exchange rate fluctuations. CONSOL Energy sold its 50% interest in the Glennies Creek Mine as of February 25, 2004. As part of the transaction, the purchaser will assume CEA’s debt related to Glennies Creek Mine and the associated hedging arrangements.

 

Other income also includes a $3 million refund received from the federal government for harbor maintenance fees imposed by federal statute that was declared unconstitutional. We have pursued claims for these fees since 1991, and we do not expect other refunds related to these claims.

 

The increases in other income were partially offset in the 2003 period compared to the 2002 period due to $7 million of income related to a contract settlement which occurred in the 2002 period.

 

An additional $2 million increase in other income was due to various transactions that occurred throughout both periods, none of which were individually material.

 

Costs

 

     2003
Period


   2002
Period


   Dollar
Variance


    Percentage
Change


 

Cost of Goods Sold and Other Charges

                            

Produced Coal

   $ 1,238    $ 1,197    $ 41     3.4  %

Purchased Coal

     72      80      (8 )   (10.0 )%

Gas

     84      65      19     29.2  %

Industrial Supplies

     66      70      (4 )   (5.7 )%

Closed and Idle Mines

     62      79      (17 )   (21.5 )%

Other

     102      52      50     96.2  %
    

  

  


 

Total Cost of Goods Sold

   $ 1,624    $ 1,543    $ 81     5.2  %
    

  

  


 

 

Increased cost of goods sold and other charges for our produced coal was due mainly to the increased cost per unit of produced coal sold, offset, in part, by reduced sales tons.

 

    

2003

Period


  

2002

Period


   Variance

   

Percentage

Change


 

Produced tons sold (in millions)

     60.9      63.2      (2.3 )   (3.6 )%

Average cost of goods sold and other charges per ton

   $ 20.34    $ 18.94    $ 1.40     7.4 %

 

Average cost of goods sold and other charges per ton for produced coal increased due mainly to increased medical expenses for retired employees and increased salaried pension expenses. Retiree medical and salaried pension expenses are actuarially determined based on several assumptions as discussed in “Critical Accounting Policies” and in the notes to the consolidated financial statements. Cost per ton for produced coal also increased

 

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due to higher supply cost per unit. These increases in costs were offset, in part, by a reduction in our produced sales volumes.

 

Purchased coal cost of goods sold and other charges decreased due primarily to a reduction in the average cost per ton and reduced volumes of purchased coal sold.

 

    

2003

Period


  

2002

Period


   Variance

   

Percentage

Change


 

Purchased tons sold (in millions)

     2.4      2.5      (0.1 )   (4.0 )%

Average cost of goods sold and other charges per ton

   $ 30.31    $ 32.15    $ 1.84     5.7 %

 

The reduced average cost of purchased coal is primarily due to purchasing coal in the 2003 period under commitments made during the prior year when prices were lower . The lower average cost of purchased coal is also attributable to CONSOL Energy purchasing and reselling a lower quality coal in the 2003 period compared to the 2002 period.

 

Gas cost of goods sold and other charges increased due to increased average cost per thousand cubic feet sold and increased volumes.

 

    

2003

Period


  

2002

Period


   Variance

  

Percentage

Change


 

Gas sales volumes (in billion gross cubic feet)

     50.0      46.4      3.6    7.8 %

Average cost per thousand cubic Feet

   $ 1.69    $ 1.40    $ 0.29    20.7 %

 

The increase in average cost per thousand cubic feet of gas sold was attributable to a $0.21 increase per thousand cubic feet in royalty expense. Royalty expense increased primarily due to the 31.2% increase in average sales price per thousand cubic feet in the 2003 period compared to the 2002 period. The increase is also due to additional employees, additional contractor maintenance cost and additional power charges attributable to the increased number of wells in production in the period-to-period comparison. Gas cost of goods sold and other charges also increased due to the increased volumes sold in the 2003 period as discussed previously. We currently plan to drill approximately 300 wells in the twelve-month period ending December 31, 2004. Variable costs on a per unit basis are not anticipated to increase as a result of the 2004 drilling program, although, due to the uncertainty of costs such as maintenance, contract labor, and corporate overhead, the incremental impact of the drilling program on per unit costs for 2004 cannot be reasonably predicted.

 

Industrial supplies cost of goods sold decreased due to reduced sales volumes.

 

Closed and idle mine cost decreased primarily due to approximately $28 million of expense related to mines that were idled for all or part of the 2002 period that were operating in the 2003 period, or that were closed in the 2002 period. These mines include idled Loveridge, Shoemaker, McElroy, and Humphrey which was closed. Closed and idle mine cost also decreased approximately $2 million due to the reduction of workforce at Rend Lake mine in the 2003 period related to the mine being placed on long-term idle status pending market conditions. These costs also decreased approximately $2 million due to differences in the 2003 engineering survey adjustments related to mine closing and reclamation compared to the 2002 engineering survey adjustments. The additional $2 million decrease in closed and idle mine cost was due to various miscellaneous transactions which occurred throughout both periods, none of which were individually material. The decreases in closed and idle mine cost were offset, in part, by approximately $17 million of additional mine closing and reclamation expenses related to changes in the method of accounting for these liabilities. In January 2003, CONSOL Energy adopted the Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”. Under this statement, the interest accretion related to the discounted portions of mine closing, reclamation and gas well closing liabilities, previously reported as interest expense, are now reported as operating expenses. Under the previous method of accounting for mine closing, reclamation and gas well closing

 

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obligations, the estimated obligations for closed mines were fully accrued and adjusted annually as the estimates were updated by engineers. Miscellaneous cost of goods sold and other charges increased due to the following items:

 

     2003
Period


   2002
Period


   Dollar
Variance


   Percentage
Change


 

Loveridge fire

   $ 17    $ —      $ 17    100.0  %

Mine Eighty-Four fire

     5      —        5    100.0  %

Litigation settlements and contingencies

     18      11      7    63.6  %

Cardinal River severance and pension cost

     2      —        2    100.0  %

Supply inventory write-downs

     5      —        5    100.0  %

Miscellaneous transactions

     55      41      14    34.1  %
    

  

  

      
     $ 102    $ 52    $ 50    96.2  %
    

  

  

      

 

In February 2003, Loveridge Mine experienced a fire near the bottom of the slope entry that is used to carry coal from the mine to the surface. The costs of extinguishing the fire are estimated to be approximately $17 million attributable to cost of goods sold and other charges and other related expenses are estimated to be approximately $3 million, net of expected insurance recovery applicable to both the cost of goods sold and other expenses. In late December 2002, the mine had begun the process of developing a new underground area that would be mined with longwall mining equipment that was expected to be installed later in 2003. The fire has delayed this installation until March 2004.

 

In January 2003, Mine Eighty-Four experienced a fire along several hundred feet of the conveyor belt entry servicing the longwall section of the mine. The fire was extinguished approximately two weeks later. On January 20, 2003, the mine resumed production on a limited basis with continuous mining machines, while repairs continued on the belt entry. The fire caused damage to the roof support system, the conveyor belt and the steel framework on which the belt travels. Repairs took several weeks to complete and are estimated to cost approximately $5 million attributable to cost of goods sold and other related charges and $2 million attributable to other expenses, net of expected insurance recovery applicable to both the cost of goods sold and to other expenses. Longwall coal production, which accounts for the majority of coal normally produced at the mine resumed on February 10, 2003.

 

Litigation settlements and contingencies increased over the prior year due to various contingent loss accruals related to various individual contingencies, waste management accruals and asbestos claims in both periods, none of which are individually material.

 

CONSOL Energy owned a 50% interest in Cardinal River until February 2003, when it and related assets were sold. Cardinal River mine severance and pension accruals are attributable to the costs for which CONSOL Energy remains responsible following the sale of the mine’s assets. Supply inventory write-downs reflect adjustments made to supply inventories that are unique to the equipment used at locations where the mining activities have ceased, such as the Dilworth and Rend Lake mines.

 

Cost of goods sold and other charges also increased due to various miscellaneous transactions which occurred throughout both periods, none of which are individually material.

 

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to whom CONSOL Energy contractually provides transportation. Freight expense is billed to customers and the revenue from such billing equals the transportation expense.

 

    

2003

Period


  

2002

Period


  

Dollar

Variance


   

Percentage

Change


 

Freight expense

   $ 115    $ 134    $ (19 )   (14.2 )%

 

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Selling, general and administrative costs have increased due to the following items:

 

    

2003

Period


  

2002

Period


  

Dollar

Variance


  

Percentage

Change


 

Wages and salaries

   $ 29    $ 27    $ 2    7.4 %

Other post employment and pension costs

     11      6      5    83.3 %

Professional consulting and other purchased services

     15      11      4    36.4 %

Other

     23      22      1    4.5 %
    

  

  

  

Total selling, general and administrative

   $ 78    $ 66    $ 12    18.2 %
    

  

  

  

 

Wages and salaries for selling, general and administrative employees have increased primarily due to merit increases, promotions and new hires throughout the 2003 period. In December 2003, CONSOL Energy implemented a reduction in workforce program primarily focused on reducing the number of positions in the selling, general and administrative areas to better align with its current business strategy. This program is expected to reduce approximately 100 positions and approximately $10 million of wages, salaries and benefits in the administrative functions in the 2004 period.

 

Other post employment and pension costs have increased due mainly to increased medical expenses for retired employees and changes in actuarial assumptions used for pension. Retiree medical and salaried pension expenses are actuarially determined based on several assumptions as discussed in “Critical Accounting Policies” and in the notes to the consolidated financial statements included in this prospectus.

 

Costs of professional consulting and other purchased services have increased in the 2003 period primarily due to services provided in relation to a special investigation into matters alleged in an anonymous letter and transactions in connection with the reduction by RWE Rheinbraun, the former controlling stockholder, of its percentage ownership in CONSOL Energy.

 

Other selling, general and administrative costs increased primarily due to the cost of director and officer insurance costs incurred in the 2003 period. CONSOL Energy officers and directors were previously insured under the RWE AG general liability policy.

 

Depreciation, depletion and amortization has decreased due to the following items:

 

    

2003

Period


  

2002

Period


  

Dollar

Variance


   

Percentage

Change


 

Coal

   $ 196    $ 218    $ (22 )   (10.1 )%

Gas

     33      34      (1 )   (2.9 )%

Other

     13      11      2     18.2 %
    

  

  


     

Total depreciation, depletion and amortization

   $ 242    $ 263    $ (21 )   (8.0 )%
    

  

  


     

 

The decrease in coal depreciation, depletion and amortization was primarily attributable to the equipment at the Dilworth mine and the related preparation plant becoming fully depreciated prior to the 2003 period to coincide with the closure of the mine due to economically depleted reserves and other mine equipment becoming fully depreciated in the 2003 period. The decrease also relates to lower units-of-production financial depletion due to lower production volumes in the 2003 period compared to the 2002 period. Decreases in coal depreciation, depletion and amortization were offset, in part, by a $4 million increase due to the depreciation of the assets recorded in relation to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). SFAS No. 143 requires depreciation of the capitalized asset retirement cost. The depreciation of these assets is generally determined on a units-of-production basis over the life of the producing asset.

 

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The decrease in gas depreciation, depletion and amortization was primarily due to a higher ratio of gas production coming from mine gob areas which have lives generally less than twelve months long. As a result the costs to produce these areas are expensed instead of capitalized and then amortized. This gob gas production is not included in the calculation of units-of-production depreciation or depletion for capitalized gas costs. The reduction in gas depreciation, depletion and amortization was offset, in part, by additional depreciation attributable to new assets placed in service during the 2003 period and additional depletion and depreciation related to the increased volumes from other than gob wells produced during the 2003 period. The reductions were also offset, in part, by a $1 million increase due to the depreciation of the assets recorded in relation to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). SFAS No. 143 requires depreciation of the capitalized asset retirement cost. The depreciation of these assets is generally determined on a units-of-production basis over the life of the producing asset.

 

The increase in other depreciation, depletion and amortization was primarily due to additional depreciation on the integrated information technology system installed to support business processes. The system was implemented in stages beginning in January 2001 and was substantially completed in August 2003.

 

Interest expense has decreased primarily due to the following items:

 

    

2003

Period


  

2002

Period


  

Dollar

Variance


   

Percentage

Change


 

Mine closing, reclamation and gas well closing liabilities

   $ —      $ 9    $ (9 )   (100.0 )%

Commercial paper

     1      6      (5 )   (83.3 )%

Other

     33      31      2     6.5 %
    

  

  


     

Total Interest Expense

   $ 34    $ 46    $ (12 )   (26.1 )%
    

  

  


     

 

Interest accretion on the discounted portions of mine closing, reclamation and gas well closing liabilities changed due to the implementation of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” Under this statement, the interest accretion related to the discounted portions of mine closing, reclamation and gas well closing liabilities, previously reported as interest expense, are now reported as operating expense.

 

Interest expense on commercial paper decreased primarily due to a $205 million reduction in the weighted average principal amount of commercial paper outstanding and a 1.0% per annum reduction in the weighted average interest rate on amounts outstanding in the 2003 period. As of July 2003, CONSOL Energy was no longer able to participate as a seller of commercial paper due to Standard and Poor’s lowering its rating of our long-term debt to BB+. Subsequently, CONSOL Energy’s debt ratings have been lowered by Standard and Poor’s and Moody’s.

 

Other interest expense increased due primarily to a $4 million increase in interest expense related to the $250 million principal amount of 7.875% Notes due in 2012, which were issued in March 2002 and therefore were not outstanding for the entire 2002 period. This increase was offset, in part, by a $2 million reduction in interest expense due to the reduction of long-term debt through scheduled debt repayments.

 

Taxes other than income decreased primarily due to the following items:

 

    

2003

Period


  

2002

Period


  

Dollar

Variance


   

Percentage

Change


 

Payroll taxes

   $ 32    $ 35    $ (3 )   (8.6 )%

Property and other taxes

     23      28      (5 )   (17.9 )%

Capital stock and franchise tax

     1      6      (5 )   (83.3 )%

Production taxes

     104      103      1     0.9 %
    

  

  


     

Total Taxes Other Than Income

   $ 160    $ 172    $ (12 )   (7.0 )%
    

  

  


     

 

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Payroll taxes have decreased primarily due to the closure or idling of several mines in the period-to-period comparison. Dilworth, Rend Lake and Humphrey mines were not operating in the 2003 period and, therefore, the average number of employees was lower in the 2003 period compared to the 2002 period.

 

Decreased property and other taxes are attributable to the adjustment of prior year estimated accruals to the actual amounts paid in the 2003 period.

 

Capital stock and franchise tax has been reduced in the 2003 period due to the impacts of merging several CONSOL Energy companies over the past several years.

 

Increased production taxes are primarily due to higher severance taxes attributable to higher gas production volumes and associated sales price in the 2003 period compared to the 2002 period. This increase was offset, in part, by decreased black lung excise taxes related to the lower coal production volumes.

 

Restructuring Costs

 

Restructuring costs of approximately $4 million in the 2003 period primarily represent the severance dollars paid related to the December 2003 reduction in workforce program implemented by CONSOL Energy. The program was primarily focused on reducing the number of positions in the selling, general and administrative areas and is expected to reduce approximately 100 positions and approximately $10 million of wages, salaries and benefits in the administrative functions in the 2004 period. Also included in the restructuring costs are severance amounts paid throughout 2003 for positions that have been eliminated by CONSOL Energy management in an effort to reduce costs and realign our selling, general and administrative functions with today’s strategies.

 

Export Sales Excise Tax Resolution

 

CONSOL Energy is no longer required to pay certain excise taxes on export sales. We have received refunds and related interest in the 2003 period for our claims for the years 1994 to 1999. Upon receipt of these refunds, we have adjusted our estimate of interest receivable to the amounts received. This adjustment resulted in additional income of $1 million in the 2003 period. A receivable for the claims for the years 1991to 1993 is still outstanding. There is no interest receivable related to these claims.

 

Income Taxes

 

    

2003

Period


   

2002

Period


    Variance

   

Percentage

Change


 

Earnings (Loss) Before Income Taxes

   $ (34 )   $ (40 )   $ 6     15.0 %

Tax Expense (Benefit)

     (21 )     (52 )     31     (59.6 )%

Effective Income Tax Rate

     62.4 %     128.9 %     (66.5 )%      

 

CONSOL Energy’s effective tax rate is sensitive to changes in annual profitability and percentage depletion. The 2003 effective tax rate changed from the 2002 effective rate primarily due to the tax effect of the current year’s sale of our Canadian assets. Another significant cause of the change was due to provision to return adjustments recorded in 2002. See note 9 of notes to the consolidated financial statements included in this prospectus.

 

Cumulative Effect of Changes in Accounting for Mine Closing, Reclamation and Gas Well Closing Costs

 

Effective January 1, 2003, CONSOL Energy adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”, as required. CONSOL Energy reflected a gain of approximately $5 million, net of a tax cost of approximately $3 million. At the time of adoption, total assets, net of accumulated depreciation, increased

 

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approximately $59 million and total liabilities increased approximately $51 million. The amounts recorded upon adoption are dependent upon a number of variables, including the estimated future retirement costs, estimated proved reserves, assumptions involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rate.

 

Previous accounting standards generally used the units-of-production method to match estimated retirement costs with the revenues generated by the producing assets. In contrast, SFAS No. 143 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines. Because of the long lives of the underlying producing assets, the impact on net income in the near term is not expected to be material.

 

Twelve Months Ended December 31, 2002 compared with Twelve Months Ended December 31, 2001 (unaudited)

 

Net Income

 

CONSOL Energy’s net income for the twelve months ended December 31, 2002 was $12 million compared with $151 million for the twelve months ended December 31, 2001. Pre-tax income for the 2001 period was $183.4 million including $118.1 million related to the recognition of the export sales excise tax resolution. CONSOL Energy had a pre-tax loss of $40.4 million in the 2002 period. Lower net income for 2002 was also the result of a 9 million ton reduction in volumes of our produced coal sold. The decrease in tons sold was due primarily to lower demand for coal in the 2002 period. Demand was weak primarily due to the continued sluggish United States economy and the lingering effect of higher than normal customer inventory levels. The decrease in tons sold was also due to the deferral of shipments by our customers during the year to later periods and reduced volumes from requirements contracts. Decreases in net income also resulted from lower average sales prices per million British thermal unit of coalbed methane gas sold in the 2002 period compared to the 2001 period. The average sales price was $3.22 per million British thermal units for the year to date 2002 period, a $0.66, or 17.0% decrease compared to the $3.88 per million British thermal unit in the 2001 period. The decrease in average sales price was primarily due to reduced demand for gas in the industrial sector and lower demand for gas during the winter heating season that resulted in high levels of gas in storage. Net income also decreased due to increased cost of goods sold related to the increase in gas volumes sold. Costs also increased due to additional closed and idle mine costs, additional purchased coal costs and increases in miscellaneous cost of goods sold and other operating charges. These decreases were offset, in part, by income tax benefits recognized in the 2002 period compared to tax expense recognized in the 2001 period. The income tax benefit was due mainly to a pre-tax loss for the 2002 period compared to pre-tax income in the 2001 period without a comparable reduction in percentage depletion tax benefits. Decreases in net income were also offset, in part, by higher volumes of gas sold as a result of the August 22, 2001 acquisition of the remaining 50% interest in Pocahontas Gas Partnership. Gas sales volumes were 46.9 billion cubic feet in the 2002 period, a 44.5%, or 14.5 billion cubic feet increase from the 2001 period. Average sales price per ton of our produced coal sold also increased which offset, in part, the reduction to net income. The average sales price for our produced coal was $26.80 in the 2002 period compared to $24.88 in the 2001 period. The increase of $1.92, or 7.7%, reflects the higher prices negotiated in 2001’s more favorable coal market.

 

Revenue

 

Sales decreased $92 million, or 4.4% to $2,003 million for the twelve months ended December 31, 2002 from $2,095 million for the twelve months ended December 31, 2001.

 

Revenues from the sale of our produced coal decreased $101 million, or 5.6%, to $1,694 million in the 2002 period from $1,795 million in the 2001 period. The decrease in our produced coal sales revenues was due mainly to a decrease in the volume of our produced coal sold. Produced coal sales volumes were 63 million tons in the

 

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2002 period, a 9 million ton, or 12.4%, decline from the 72 million tons sold in the 2001 period. The decrease in tons sold was due primarily to lower demand for coal in the 2002 period. Demand was weak primarily due to the continued sluggish United States economy and the lingering effect of higher than normal customer inventory levels. The decrease in tons sold was also due to the deferral of shipments by our customers during the year to later periods and reduced volumes from requirements contracts. The decrease in tons sold was offset, in part, by increases in the average sales price per ton of our produced coal sold. The average sales price for our produced coal was $26.80 in the 2002 period compared to $24.88 in the 2001 period. The increase of $1.92, or 7.7%, reflects the higher prices negotiated in 2001’s more favorable coal market.

 

Revenues from the sale of industrial supplies decreased $22 million, or 25.0%, to $64 million in the 2002 period from $86 million in the 2001 period primarily due to reduced sales volumes. During the fiscal year ended June 30, 2001, the physical assets and operations associated with 18 industrial and store management sites were sold. The sale did not have a material impact on CONSOL Energy’s financial position, results of operations or cash flow. Fairmont Supply continues to operate 12 service centers.

 

These decreases in revenues were partially offset by increased revenues from the sale of coalbed methane gas. Revenues from the sale of gas increased $25 million, or 20.2% to $147 million in the 2002 period from $122 million in the 2001 period. The increase was due mainly to higher volumes of gas sold as a result of the August 22, 2001 acquisition of the remaining 50% interest in Pocahontas Gas Partnership. Sales volumes were 46.9 billion cubic feet in the 2002 period, a 44.5%, or 14.5 billion cubic feet increase from the 2001 period. The increase in sales volumes was offset, in part, by lower average sales prices in the 2002 period compared to the 2001 period. The average sales price was $3.22 per million British thermal units for the year to date 2002 period, a $0.66, or 17.0% decrease compared to the $3.88 per million British thermal unit in the 2001 period. The decrease in average sales price was primarily due to reduced demand for gas in the industrial sector and lower demand for gas during the winter heating season that resulted in higher levels of gas in storage in the beginning of the 2002 period compared to the 2001 period.

 

Revenues from the sale of purchased coal increased $5 million, or 6.9%, to $83 million in the 2002 period from $78 million in the 2001 period primarily due to increased average sales prices. The average sales price per ton of purchased coal increased $5.39, or 19.2%, to $33.50 in the 2002 period compared to $28.12 in the 2001 period. The increase in price per ton reflects the higher prices negotiated in 2001’s more favorable coal market. This increase was offset, in part, by reduced sales volumes. Sales volumes decreased 0.3 million tons, or 10.3%, to 2.5 million tons in the 2002 period compared to 2.8 million tons in the 2001 period. The decrease in tons sold was due primarily to lower demand for coal in the 2002 period. Demand was weak primarily due to the continued sluggish United States economy and the lingering effect of higher than normal customer inventory levels.

 

Freight revenue, outside and related party, decreased $25 million, or 15.5%, to $134 million in the 2002 period from $159 million in the 2001 period. Freight revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (e.g., rail, barge or truck) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred.

 

Other income, which consists of interest income, gain or loss on the disposition of assets, equity in earnings of affiliates, service income, royalty income, rental income and miscellaneous income, was $46 million in the 2002 period compared to $65 million in the 2001 period. The decrease of $19 million, or 29.0%, was primarily due to the $21 million reduction in equity in earnings of affiliates. This was mainly due to the August 22, 2001 purchase of the remaining 50% interest in Pocahontas Gas Partnership and the remaining 25% interest in the Cardinal States Gathering Company. As a result of the acquisition, CONSOL Energy owns 100% of these entities and began to account for them as fully consolidated subsidiaries. Before the acquisition, CONSOL Energy accounted for these companies using the equity method. Other income also decreased by $5 million as a result of various transactions that occurred throughout both periods, none of which was individually material. These decreases in other income were offset, in part, by a $7 million income adjustment related to a coal contract settlement CONSOL Energy received in the 2002 period.

 

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Costs

 

Cost of Goods Sold and Other Operating Charges decreased $43 million, or 2.7%, to $1,543 million in the 2002 period from $1,586 million in the 2001 period.

 

Cost of goods sold for our produced coal decreased $42 million, or 3.4% to $1,197 million in the 2002 period from $1,239 million in the 2001 period. The decrease was primarily due to a 12.4% decrease in the volume of our produced coal sold. The decrease in tons sold was due primarily to lower demand for coal in the 2002 period. Demand was weak primarily due to the continued sluggish United States economy, and the lingering effect of higher than normal customer inventory levels. The decrease in tons sold was also due to the deferral of shipments by our customers during the year to later periods and reduced volumes from requirements contracts. The reduced cost of goods sold and other charges related to volume, was offset, in part, by a 10.3% increase in the cost per ton sold of our produced coal. The increase in cost primarily relates to employee benefit costs and supply costs. The rise in employee benefit costs is primarily due to increased medical costs and increased post employment benefit costs. Post employment benefit costs are calculated actuarially and have increased due to changes in assumptions, including discount rate and mortality tables used in this calculation.

 

Cost of goods sold for industrial supplies decreased $23 million, or 24.0%, to $70 million in the 2002 period from $93 million in the 2001 period. The decrease in costs is related to reduced sales volumes resulting from the sale of 18 industrial and store management sites that took place in the 2001 period. Fairmont Supply continues to operate 12 service centers.

 

Coal property holding costs decreased $9 million, or 66.0%, to $5 million in the 2002 period from $14 million in the 2001 period. The decrease was primarily due to leasehold surrenders that occurred in the 2001 period.

 

These decreases in cost of goods sold and other costs were offset, in part, by increased cost of goods sold for gas operations. Gas operations cost of goods sold increased $9 million, or 15.8%, to $65 million in the 2002 period from $56 million in the 2001 period. The increase was due mainly to a 44.5% increase in the volume of gas sold as a result of the August 22, 2001 acquisition of the remaining 50% interest in Pocahontas Gas Partnership. The increase in volume was offset, in part, by a $0.35, or 19.9% reduction in the cost per million British thermal units sold. The average cost per million British thermal units sold was $1.40 in the 2002 period compared to $1.75 in the 2001 period. The decrease was primarily due to a decrease in the cost of gob well drilling and lower royalty expense. Gob wells are drilled in previously mined areas of underground coal mines. Royalty expenses decreased $0.07 per British thermal unit primarily due to the 17.1% decrease in average sales price per British thermal unit in the 2002 period compared to the 2001 period.

 

Cost of goods sold for closed and idled mine costs increased $14 million, or 21.7%, to $79 million in the 2002 period from $65 million in the 2001 period. The increase is primarily due to $32 million related to locations that were closed or idled during a portion of the 2002 period that were in operation during the 2001 period. This increase was offset, in part, by a decrease of $18 million related to mine closing and reclamation liability adjustments as a result of updated engineering survey adjustments for closed and idled locations. Survey adjustments resulted in $16 million of expense recognized in the 2001 period compared to $2 million of income in the 2002 period.

 

Cost of goods sold for purchased coal increased $4 million, or 5.4%, to $80 million in the 2002 period from $76 million in the 2001 period. The increased costs were primarily due to an increase of $4.79, or 17.5%, in the average cost per ton of purchased coal, offset, in part, by a decrease of 0.3 million tons, or 10.3%, decrease in the volume of purchased tons sold. The average cost per ton of purchased coal was $32.16 in the 2002 period compared to $27.37 in the 2001 period.

 

Miscellaneous cost of goods sold and other operating charges increased $4 million, or 7.9%, to $47 million in the 2002 period from $43 million in the 2001 period. The increase is due mainly to $14 million of equipment

 

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removal cost in the 2002 period compared to $9 million in the 2001 period. The increase in the 2002 period was also due to $4 million of contribution expense related to the donation of property to The Conservation Fund and $2 million of expense to recognize an allowance for doubtful accounts related to trade receivables. Bank fees also increased $2 million in the 2002 period related to the renegotiation of our revolving credit facility. The new facility replaces the previous agreement, which expired on September 20, 2002 and allows for an aggregate of $485 million of commercial paper principal and letters of credit to be issued. Miscellaneous cost of goods sold and other operating charges also increased $9 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material. These increases in cost of goods sold and other charges were offset, in part, by an $18 million reduction in incentive compensation expense. Expense for this item was reduced in the 2002 period because performance targets for 2002 were not achieved. Miscellaneous costs of goods sold and other operating charges also includes $11 million of expense for various contingent loss accruals related to asbestos, waste management site and various other contingencies in both the 2002 period and the 2001 period.

 

Freight expense decreased $25 million, or 15.5%, to $134 million in the 2002 period from $159 million in the 2001 period. Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (e.g., rail, barge or truck) used for the customers that CONSOL Energy contractually provides transportation. Freight expense is billed to customers and the revenue from such billings equals the transportation expense.

 

Selling, general and administrative expenses increased $5 million, or 7.7%, to $66 million in the 2002 period from $61 million in the 2001 period. Administrative expenses increased $4 million due to additional wages, salaries and other costs related to executive severance which occurred in the 2002 period and increased medical costs in the 2002 period. An increase of $2 million was primarily due to expenses for training, licensing fees and professional consulting related to the conversion to a new integrated information technology system provided by SAP AG to support business processes. Implementation of the system was completed in 2003 at an estimated total cost of $53 million, a portion of which was capitalized. These increases were offset, in part, by a $1 million decrease in selling costs due to the reduction of sales employees at Fairmont Supply related to the sale of 18 industrial and store management sites that took place in the 2001 period. Fairmont Supply continues to operate 12 service centers.

 

Depreciation, depletion and amortization expense increased $19 million, or 7.9%, to $263 million in the 2002 period compared to the $244 million in the 2001 period. The increase was primarily due to the August 22, 2001 acquisition of the remaining 50% interest in Pocahontas Gas Partnership and the remaining 25% interest in the Cardinal States Gathering Company. In the 2002 period, these entities were reported as fully consolidated. In the 2001 period, these entities were reported on the equity basis. Depreciation and amortization also increased due to more coal assets being placed in service in the 2002 period. These increases were offset, in part, by lower financial depletion related to the reduced production levels in the 2002 period compared to the 2001 period.

 

Interest expense increased $3 million, or 6.6%, to $46 million in the 2002 period compared to $43 million in the 2001 period. This was due primarily to $16 million of additional interest expense related to the March 7, 2002 issuance of $250 million of 7.875% Notes due in 2012. The interest on the notes is payable March 1 and September 1 of each year commencing September 1, 2002. This increase was offset, in part, by a $9 million reduction in interest expense related to commercial paper. The reduction was due primarily to a $13 million reduction in the average levels of commercial paper outstanding during the 2002 period compared to the 2001 period, along with a decrease of 2.3% per annum in average interest rates in the period-to-period comparison. Interest expense was also reduced $4 million due to the reduction of long-term debt through scheduled payments.

 

Taxes other than income increased $11 million, or 7.2%, to $172 million in the 2002 period compared to $161 million in the 2001 period. The increase was due primarily to increased black lung excise taxes, real estate and personal property taxes and state reclamation fee taxes in the 2002 period compared to the 2001 period. In the 2001 period, due to certain black lung excise taxes being declared unconstitutional, $11 million of prior year

 

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accruals, which were not paid and were no longer owed, were reversed. The increase in certain taxes was offset by $4 million due to the reduction of 7 million tons of production in the 2002 period compared to the 2001 period. Real estate and personal property taxes increased $8 million in the 2002 period compared to the 2001 period. This increase was due to $3 million of additional taxes related to the properties owned by Windsor Coal Company, Southern Ohio Coal Company, Central Ohio Coal Company, Pocahontas Gas Partnership and Cardinal States Gathering Company which were acquired in 2001. Real estate and personal property taxes also increased $1 million due to expanded permitting at our mining locations. The remaining $4 million increase in real estate and personal property taxes was related to several transactions throughout the 2002 and 2001 periods, none of which were individually material. These increases in taxes other than income were offset, in part, by a $3 million reduction in payroll taxes. The reduction in payroll taxes is primarily due to reduced employee counts as a result of several mines being idled during the 2002 period. Taxes other than income also decreased $1 million as a result of various transactions throughout the 2002 and 2001 periods, none of which were individually material.

 

CONSOL Energy is no longer required to pay certain excise taxes on export coal sales. We have filed claims with the Internal Revenue Service seeking refunds for these excise taxes that were determined to be unconstitutional and were paid during the period 1991 through 1999. During the 2001 period, we recognized $92 million of pre-tax earnings net of other charges and $26 million of interest income related to these claims. During the 2002 period, we recognized $1 million of interest income related to these claims. In the 2002 period, $4 million has been collected on these claims. A $93 million receivable remains in Other Receivables at December 31, 2002.

 

Income Taxes

 

Income taxes represent a $52 million benefit in the 2002 period compared to $32 million of expense in the 2001 period. The decrease in tax expense was due mainly to a pre-tax loss of $40 million in the 2002 period compared to pre-tax income of $183 million in the 2001 period without a comparable reduction in percentage depletion tax benefits.

 

Our effective tax rate is sensitive to changes in annual profitability and percentage depletion. The effective rate was 128.9% in the 2002 period compared to 17.5% in the 2001 period. Although we suffered a loss for the year, the percentage depletion deduction allowed for tax purposes did not have a corresponding reduction. Historically, the annual depletion benefit has been approximately $30 million. The combination of this benefit and a pre-tax loss resulted in our effective tax rate. Additional detail is provided in note 9 of notes to consolidated financial statements.

 

Income taxes were also reduced due to adjusting the provision for income taxes at the time the returns are filed. These adjustments decreased income tax expense by $4 million in the 2002 period and increased income tax expense $1 million for the 2001 period. In the 2002 period, CONSOL Energy also received a $2 million federal income tax benefit from a final agreement resolving disputed federal income tax items for the years 1995 to 1997.

 

Six Months Ended December 31, 2001 compared with Six Months Ended December 31, 2000 (unaudited)

 

Net Income

 

CONSOL Energy’s net income for the six months ended December 31, 2001 was $1 million compared with $34 million for the six months ended December 31, 2000. The decrease of $33 million was primarily due to lower prices for natural gas caused by general market declines and higher cost per ton of produced coal mined caused principally by adverse mining conditions and mechanical problems. The effects of lower prices for natural gas and higher coal production costs were offset, in part, by a reduction in income tax expense due to a pre tax loss in the 2001 transitional period along with changes in percentage depletion allowances and higher volumes of gas sold.

 

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Revenue

 

Sales decreased $28 million, or 2.8% to $964 million for the six months ended December 31, 2001 from $992 million for the six months ended December 31, 2000.

 

Revenues from the sale of coalbed methane gas and gathering fees decreased $8 million, or 13.7% to $48 million in the 2001 transitional period from $56 million in the 2000 six month period. This decrease was due mainly to a 44.2% decrease in average sales price for the period. Average sales price for the 2001 transitional period was $2.61 per million British thermal unit compared to $4.68 per million British thermal unit for the six months ended December 31, 2000. The decrease in sales price was offset, in part, by higher volumes as a result of the August 22, 2001 acquisition of the remaining 50% interest in Pocahontas Gas Partnership. Sales volumes were 18.6 billion cubic feet in the 2001 transitional period, an increase of 6.5 billion cubic feet, or 53.4% from the 2000 six-month period.

 

Revenues from the sale of industrial supplies decreased $30 million, or 46.5%, to $34 million in the 2001 transitional period from $64 million in the 2000 six month period. The decrease was due primarily to the sale of the physical assets, inventory and operations associated with 18 industrial and store management sites during the 2000 six month period. The sale did not have a material impact on CONSOL Energy’s financial position, results of operations or cash flow.

 

These decreased revenues were partially offset by increased revenues from the sale of our produced coal. Revenues from the sale of our produced coal increased $14 million, or 1.7%, to $836 million in the 2001 transitional period from $822 million in the 2000 six month period. The increase in produced coal sales revenues was due mainly to an increase of $1.62, or 6.9%, in the average sales price per ton sold. The average sales price was $25.07 in the 2001 transitional period compared to $23.45 in the 2000 six month period. The increase in average sales price was due primarily to demand increases and low inventory levels at coal producers. The increase in average sales price was partially offset by a 2 million ton, or 4.8%, decrease in the volume of produced tons sold in the 2001 transitional period compared to the 2000 six month period. Produced coal sales volumes were 33 million tons in the 2001 transitional period compared to 35 million tons in the 2000 six-month period. The decreased sales volumes were due primarily to the decline in production as a result of the suspension of longwall production at Mine 84 early in July 2001. Mine 84 restarted longwall production in early December 2001 at production levels equal to full production levels in the months before production problems were encountered. This start was approximately one month earlier than originally projected. Production shortages were encountered at several other CONSOL Energy mines due to mechanical and geological difficulties. These production declines were offset by the production at several of the mines acquired from American Electric Power on July 2, 2001.

 

Revenues from the sale of purchased coal decreased $11 million, or 21.6%, to $40 million in the 2001 transitional period from $51 million in the 2000 six-month period. Sales volumes decreased 13.3% to 1.3 million tons in the 2001 transitional period from 1.5 million tons in the 2000 six-month period. The decreased volumes were partially offset by a 4.8% increase in the price per ton of purchased coal sold. The average sales price per ton of purchased coal was $29.84 in the 2001 transitional period compared to $28.49 in the 2000 six-month period.

 

Freight revenue, outside and related party, decreased $2 million, or 2.6%, to $70 million in the 2001 transitional period from $72 million in the 2000 six month period. Freight revenue is the amount billed to customers for transportation costs incurred.

 

Other income, which consists of interest income, gain or loss on the disposition of assets, equity in earnings of affiliates, service income, royalty income, rental income and miscellaneous income, was $31 million in the 2001 transitional period compared to $37 million in the 2000 six month period. The decrease of $6 million, or 16.0%, was primarily due to the reduction in equity in earnings of affiliates. The reduction in equity in earnings

 

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of affiliates was primarily due to the August 22, 2001 purchase of the remaining 50% interest in Pocahontas Gas Partnership and the remaining 25% interest in the Cardinal States Gathering Company. As a result of the acquisition, CONSOL Energy owns 100% of these entities and began to account for them as fully consolidated subsidiaries. Before the acquisition, CONSOL Energy accounted for these companies using the equity method.

 

Costs

 

Cost of Goods Sold and Other Operating Charges increased $31 million, or 4.2%, to $761 million in the 2001 transitional period from $730 million in the 2000 six month period.

 

Cost of goods sold for our produced coal increased $28 million, or 4.8% to $623 million in the 2001 transitional period from $595 million in the 2000 six month period. The increase was primarily due to a 10.1% increase in the cost per ton sold of our produced coal, offset slightly by a 4.8% decrease in the volume of tons of our produced coal sold. The increased cost per ton produced is primarily due to a decline in productivity as measured in tons produced per manday. Manday is a term used to describe the scheduled hours worked per person per day. This term is sometimes used to determine productivity of our mining complexes. Tons produced per manday were 37.6 in the 2001 transitional period compared to 41.6 in the 2000 six-month period. The decline in productivity is mainly due to several mines experiencing mechanical and geological difficulties in the 2001 transitional period.

 

Cost of goods sold for gas operations increased $9 million, or 51.7%, to $27 million in the 2001 transitional period from $18 million in the 2000 six month period. The increase in gas costs was due primarily to 53.4% higher volume of gas sold as a result of the acquisition of the remaining 50% interest in Pocahontas Gas Partnership on August 22, 2001. Sales volumes were 18.6 billion cubic feet in the 2001 transitional period compared to 12.1 billion cubic feet in the 2000 six-month period. The cost per million British thermal units sold remained stable at $1.50 in the 2001 transitional period compared to $1.51 in the 2000 six month period.

 

Cost of goods sold for purchased coal remained consistent at $40 million in the 2001 transitional period compared to the 2000 six month period.

 

Cost of goods sold for closed and idled mine costs increased $13 million to $29 million in the 2001 transitional period from $16 million in the 2000 six month period. The increase is due primarily to a $10 million income adjustment for mine closing and perpetual care liabilities being recognized in the 2000 six-month period. The adjustment was the result of updated engineering studies and cost projections for closed and idled locations. The increase was also due to additional costs related to the closing or idling of Loveridge, Meigs #31 and Mine 84 in the 2001 transitional period compared to the 2000 six month period.

 

Cost of goods sold for industrial supplies decreased $28 million, or 44.2%, to $36 million in the 2001 transitional period from $64 million in the 2000 six month period. The decrease in costs is related to reduced sales volumes resulting from the sale of 18 industrial and store management sites.

 

Freight expense decreased $2 million, or 2.7%, to $70 million in the 2001 transitional period from $72 million in the 2000 six month period. Freight expense is billed to customers and the revenue from such billings equals the transportation expense.

 

Selling, general and administrative expenses decreased $2 million, or 5.7%, to $31 million in the 2001 transitional period from $33 million in the 2000 six-month period. The decrease was due primarily to decreased professional consulting fees. Professional consulting fees were reduced due to the completion of the review of business processes and information technology systems supporting those processes that took place in the 2000 period.

 

Depreciation, depletion and amortization expense remained stable at $120 million for the 2001 transitional period and the 2000 six-month period.

 

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Interest expense decreased by $14 million, or 46.2%, to $17 million in the 2001 transitional period compared to $31 million in the 2000 six month period. The decrease was due primarily to lower average debt levels outstanding during the 2001 transitional period compared to the 2000 six month period, along with a decrease of 3.6% per annum in average interest rates reflecting more favorable interest rates. Lower average debt levels resulted from the cash received in the acquisition of the Windsor Coal Company, Southern Ohio Coal Company and Central Ohio Coal Company from American Electric Power being used to reduce the outstanding amount of commercial paper in July 2001. Thereafter, we increased the outstanding amount of commercial paper by the issuance of approximately $155 million of commercial paper beginning in August 2001 to finance the acquisition of the remaining 50% interest in Pocahontas Gas Partnership and the remaining 25% interest in the Cardinal States Gathering Company. Also, in December 2001, approximately $18 million of commercial paper was issued to finance the acquisition of a 50% joint venture in Glennies Creek Mine. Interest expense is expected to increase during 2002 as a result of the refinancing of short-term debt with long-term notes with the interest rate of 7.875% per annum.

 

Taxes other than income increased $3 million, or 3.7%, to $81 million in the 2001 transitional period compared to $78 million in the 2000 six month period. The increase was due primarily to increased excise taxes, severance taxes and payroll taxes in the 2001 transitional period. These costs increased primarily due to the acquisition of the Windsor Coal Company, Southern Ohio Coal Company and Central Ohio Coal Company from American Electric Power.

 

CONSOL Energy is no longer required to pay certain excise taxes on export coal sales. We have filed claims with the Internal Revenue Service seeking refunds for these excise taxes that were determined to be unconstitutional and were paid during the period 1991 through 1999. During the 2001 transitional period, we recognized a $5 million reduction to the expected interest receivable amount recognized in the twelve months ended June 30, 2001 due to the change in the estimate of recoverable amounts.

 

Income Taxes

 

Income taxes were a $21 million benefit in the 2001 transitional period compared to $4 million of expense in the 2000 six-month period. The decrease of $25 million was due mainly to a pre-tax loss of $20 million in the 2001 transitional period with little loss of percentage depletion tax benefits. Our effective tax rate is sensitive to changes in annual profitability and percentage depletion.

 

Critical Accounting Policies

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities in the consolidated financial statements and at the date of the financial statements, as well as the reported amounts of income and expenses during the reporting period. Note 1 of the notes to the consolidated financial statements in this prospectus describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of the consolidated financial statements.

 

Other Post Employment Benefits

 

CONSOL Energy has historically provided retiree health benefits to employees that retire with at least ten years of service and have attained age 55. Effective August 1, 2003, the eligibility requirement for Salaried Employees was changed to either 20 years of service and age 55, or 15 years of service and age 62. Our retiree health plans provide benefits to approximately 24,000 of our former employees and their eligible dependents. Eligibility requirements for hourly employees have not changed from CONSOL Energy’s historical requirements.

 

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In addition to the change in eligibility requirements, other changes have been made to the Medical Plan which covers eligible Salaried Employees and Retirees. These changes include a new cost sharing structure where essentially all participants contribute 20% of plan costs. Annual cost increases in excess of 6% are paid entirely by the Plan participants.

 

After our review, various actuarial assumptions, including discount rate, expected trend in health care costs and per capita costs, are used by our independent actuary to estimate the cost and benefit obligations for our retiree health plan. The discount rate is determined each year at the measurement date (normally three months before the year-end date). The discount rate is an estimate of the current interest rate at which the Other Post Employment Benefit liabilities could be effectively settled at the measurement date. In estimating this rate, CONSOL Energy looks to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. For the twelve months ended December 31, 2003, the discount rate used to calculate the period end liability and the following year’s expense was 6.0%. The discount rate for the twelve months ended December 31, 2002 used to calculate the period end liability and the following year’s expense was 6.75%. Changes to interest rates for the rates of returns on instruments that could be used to settle the actuarially determined plan obligations introduce substantial volatility to our costs.

 

Per capita costs on a per annum basis for Other Post Retirement Benefits were assumed to be $4,037 at December 31, 2003. This was an 11.1% increase over the per capita cost on a per annum basis at December 31, 2002. If the actual increase in per capita cost of medical services or other post retirement benefits are significantly greater or less than the projected trend rates, the per capita cost assumption would need to be adjusted annually, which could have a significant effect on the costs and liabilities recognized in the financial statements. The estimated liability recognized in our consolidated financial statements at December 31, 2003 was $1.6 billion compared to $1.5 billion at December 31, 2002.

 

For the twelve months ended December 31, 2003, we paid approximately $114 million for Other Post Employment Benefits, most of which were paid from operating cash flow. Significant increases in health and prescription drug costs for hourly retirees could have a material effect on CONSOL Energy’s operating cash flow. The effect on CONSOL Energy’s cash flow from operations for salaried employees has been limited to approximately 5% annually due to the cost sharing provision added to the benefit plan in 2003.

 

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. As permitted by recently issued accounting guidance, as of December 31, 2003, CONSOL Energy will defer accounting for the effects of the Act in the measure of its Accumulated Postretirement Benefit Obligation or APBO and the effect of the offset to plan costs. Specific guidance with respect to accounting for the effects of the Act has not been issued. Specific authoritative guidance, when issued, could require CONSOL Energy to change previously reported information. The impacts of the law change are currently being evaluated and currently are expected to result in a decrease of the APBO of between $80 and $160 million. Recognition of the subsidy as an offset to annual plan costs are preliminarily expected to be in the range of between $13 and $26 million.

 

Coal Workers’ Pneumoconiosis

 

CONSOL Energy is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease. CONSOL Energy is also responsible under various state statutes for pneumoconiosis benefits. After our review, our independent actuaries calculate the actuarial present value of the estimated pneumoconiosis obligation based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and discount rates. The discount rate is determined each year at the

 

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measurement date (normally three months before the year-end date). The discount rate is an estimate of the current interest rate at which the Coal Workers’ Pneumoconiosis liabilities could be effectively settled at the measurement date. In estimating this rate, CONSOL Energy looks to rates of return on high-quality, fixed income investments that receive one of the two highest ratings given by a recognized ratings agency. For the twelve months ended December 31, 2003, the discount rate used to calculate the period end liability and the following year’s expense was 6.0%. The discount rate for the twelve months ended December 31, 2002 used to calculate the period end liability and the following year’s expense was 6.75%. In January 2001, the United States Department of Labor amended the regulations implementing the federal black lung laws to give greater weight to the opinion of a claimant’s treating physician, expand the definition of black lung disease and limit the amount of medical evidence that can be submitted by claimants and respondents. The amendments also alter administrative procedures for the adjudication of claims, which according to the Department of Labor, results in streamlined procedures that are less formal, less adversarial and easier for participants to understand. These and other changes to the federal black lung regulations could result in changes in assumptions used in our actuarial determination of the liability, including interest, disability and mortality assumptions. Our experience to date related to these changes is not sufficient to determine the impact of these changes. These changes could significantly increase our exposure to black lung benefit liabilities. The estimated liability recognized in our consolidated financial statements at December 31, 2003 was approximately $456 million compared to $462 million at December 31, 2002.

 

At December 31, 2003, the fair value of plan assets for Coal Workers’ Pneumoconiosis was $2 million. Our historical policy has been to pay for these claims from operating cash flow, and not to fund specific amounts into restricted accounts. In 1998, a trust fund valued at approximately $18 million was acquired as part of our acquisition of Rochester & Pittsburgh Coal Company. In 2000, as part of a contract renegotiation, we acquired an additional $42 million that was placed into the trust for Coal Workers’ Pneumoconiosis. As part of the acquisition of several mining companies from American Electric Power in 2001, an additional $31 million was placed into a trust fund for Coal Workers’ Pneumoconiosis. After Internal Revenue Service approval, these funds have been used to pay all of CONSOL Energy’s Coal Workers’ Pneumoconiosis benefits. This fund will be exhausted early in 2004, at which time we plan to resume paying these benefits from operating cash flow. For the twelve months ended December 31, 2003, we paid Coal Workers’ Pneumoconiosis benefits of approximately $13 million, of which approximately $2 million was paid from operating cash flow.

 

Salaried Pensions

 

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer retirement plans. The benefits for these plans are based primarily on years of service and employees’ compensation near retirement. After our review, our independent actuaries calculate the actuarial present value of the estimated retirement obligation based on assumptions including rates of compensation, mortality rates, retirement age and interest rates. For the year ended December 31, 2003, compensation increases are assumed to range from 3% to 6% depending on age classification. This assumption was also used in the twelve months ended December 31, 2002. Retirement rate assumptions and mortality assumptions were unchanged for the year ended December 31, 2003. Retirement rate assumptions begin at 5% for employees at age 50 and increases gradually to 100% for employees at age 65. The discount rate is determined each year at the measurement date (normally three months before the year-end date). The discount rate is an estimate of the current interest rate at which the retirement plans could be effectively settled at the measurement date. In estimating this rate, CONSOL Energy looks to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. For the twelve months ended December 31, 2003 the discount rate used to calculate the period end liability and the following year’s expense was 6.0%. The discount rate for the twelve months ended December 31, 2002 used to calculate the period end liability and the following year’s expense was 6.75%. Changes to any of these assumptions introduce substantial volatility to our costs. The estimated liability at December 31, 2003 was $137 million compared to $122 million at December 31, 2002. Due to the negative actuarial return on plan assets, the difference in the accumulated benefit obligation and the plan assets at December 31, 2003 of approximately

 

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$158 million was recognized as a minimum pension liability. At December 31, 2002, the minimum pension liability was approximately $150 million. CONSOL Energy expects to contribute approximately $57 million to the pension plan in 2004.

 

The CONSOL Energy salaried plan allows for lump-sum distributions at the employees’ election. According to Statement of Financial Accounting Standard No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits”, if the lump-sum distributions made for the plan year, which is October 1 to September 30, exceed the total of the service cost and interest cost for the plan year settlement accounting is required. If this trigger event were to occur, CONSOL Energy would need to recognize in the current year’s earnings an adjustment equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum in that year. Generally, due to the lower interest rates currently being used to calculate lump-sum distributions, the impact would be to recognize actuarial losses. If this settlement accounting is triggered, the adjustment could materially impact net income.

 

Workers’ Compensation

 

Workers’ compensation is a system by which individuals who sustain employment related physical injuries or occupational diseases are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation. Workers’ compensation will also compensate the survivors of workers who suffer employment related deaths. The workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy accrues for this type of liability by recognizing cost when the event occurs that gives rise to the obligation, i.e., when it is probable that the liability has been incurred and the cost can be reasonably estimated. To assist in the determination of this estimated liability CONSOL Energy utilizes the services of third party administrators in various states in which we do business to determine the liability that exists for workers’ compensation. These third parties provide information that facilitates the estimation of the liability based on their knowledge and experience concerning similar past events. The estimated liability recognized in the financial statements at December 31, 2003, including the current portion, was approximately $316 million compared to $317 million at December 31, 2002. CONSOL Energy’s policy has been to provide for workers’ compensation benefits from operating cash flow. No funding has been provided to cover these benefits. For the twelve months ended December 31, 2003, we made payments for workers’ compensation benefits of approximately $57 million, all of which was paid from operating cash flow.

 

We changed our method of accounting for workers’ compensation effective January 1, 2004. Prior to the change, we recorded our workers’ compensation liability on an undiscounted basis. Under the new method, we will record the liability on a discounted basis, which will be actuarially determined using various assumptions, including discount rate and future cost trends. We believe this change is preferable since it will align the accounting with our other long-term employee benefit obligations, which are recorded on a discounted basis. Additionally, it will provide a better comparison with our industry peers, the majority of which record the workers’ compensation liability on a discounted basis.

 

The change will be reflected as a cumulative effect from a change in accounting in the quarter ended March 31, 2004 according to Accounting Principles Board Opinion (ABP) No. 20, “Accounting Changes.” The effect of the change is expected to result in an income adjustment of approximately $81 million, net of approximately $51 million of deferred tax expense. The workers’ compensation liability will decrease approximately $132 million and deferred tax assets will be reduced by approximately $51 million as a result of this accounting change.

 

Reclamation and Mine Closure Obligations

 

The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. CONSOL Energy accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge where

 

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necessary. Estimates of our total reclamation and mine-closing liabilities, which are based upon permit requirements and CONSOL Energy engineering expertise related to these requirements, including the current portion, were approximately $383 million at December 31, 2003. This liability is reviewed annually by CONSOL Energy management and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental regulations change significantly.

 

Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate to the closure of mines and gas wells and the reclamation of land upon exhaustion of coal and gas reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the mine closing, reclamation and gas well closing liabilities. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.

 

SFAS No. 143 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines.

 

Contingencies

 

CONSOL Energy is currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for the resolution of these claims. This estimate has been developed in consultation with legal counsel involved in the defense of these matters and is based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. We do not believe these proceedings will have a material adverse effect on our consolidated financial position. It is possible, however, that future results of operations for any particular quarterly or annual period could be materially affected by changes in our assumptions or the effectiveness of our strategies related to these proceedings.

 

Deferred Taxes

 

CONSOL Energy accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS No. 109) which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2003, CONSOL Energy has deferred tax assets in excess of deferred tax liabilities of approximately $535 million. The deferred tax assets are evaluated periodically to determine if a valuation allowance is necessary. State net operating loss carry-forwards of $52 million have been fully reserved due to the uncertainty of realizing the benefits of these carry-forwards. However, CONSOL Energy is currently exploring several tax planning strategies that may allow a portion or all of the benefit to be recognized. No other valuation allowance has been recognized because CONSOL Energy has determined that it is more likely than not that all of these deferred tax assets will be realized.

 

Significant management judgment is required in determining the need, if any, for a valuation allowance to be recorded against the deferred tax assets. CONSOL Energy’s need for a valuation allowance is based on both positive and negative evidence regarding its ability to generate sufficient future regular taxable income to realize its deferred tax assets. For the year ended December 31, 2003, our principal evaluation focused on if, and when, CONSOL Energy would return to being a regular versus an alternative minimum taxpayer. Positive evidence included the level of sales and pricing currently being negotiated under fixed price contracts, the projected

 

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reversal of certain temporary book to tax differences, particularly minimum tax preference items and the ability to employ various tax planning strategies if required. Negative evidence included the book and tax losses generated in recent periods and the inability to achieve forecasted results in the recent periods. CONSOL Energy concluded that the deferred tax assets, other than the state net operating losses generated, were more likely than not realizable. Through its evaluation, CONSOL Energy forecasts to begin paying regular tax and utilizing the alternative minimum deferred tax asset within five years. Our judgments regarding future profitability may change due to future market conditions, our ability to successfully execute our business strategy and other factors. These changes, if any, may require possible valuation allowances to be recognized. These allowances could materially impact net income in the period they were to be recognized.

 

Coal and Gas Reserve Values

 

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal and gas reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal and gas reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. The majority of our gas reserves have been reviewed by independent experts, Ralph E. Davis Associates, Inc. and Data and Consulting Services, a division of Schlumberger. None of our coal reserves have been reviewed by independent experts. Some of the factors and assumptions which impact economically recoverable reserve estimates include:

 

  geological conditions;

 

  historical production from the area compared with production from other producing areas;

 

  the assumed effects of regulations and taxes by governmental agencies;

 

  assumptions governing future prices; and

 

  future operating costs.

 

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal and gas attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material.

 

Liquidity and Capital Resources

 

CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt service obligations from cash generated from operations and proceeds from borrowings. In the past, a principal source of borrowings had been the issuance of commercial paper. In July 2003, Standard and Poor’s lowered its rating of our long-term debt to BB+ (11th lowest out of 22 rating categories) with a rating outlook of stable. Standard and Poor’s defines an obligation rated “BB” as less vulnerable to nonpayment than other speculative issues. However, the rating indicates that an obligor faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions, which could lead to the obligor’s inadequate capacity to meet its financial commitment on the obligation. The plus sign shows relative standing within the rating category. At the same time, Standard and Poor’s placed CONSOL Energy’s senior unsecured debt rating on CreditWatch with negative implications. As a result of the lower debt rating, CONSOL Energy was no longer able to participate as a seller in the commercial paper market. CONSOL Energy believes alternative sources of short-term borrowing, including CONSOL Energy’s Senior Revolving Credit facility and the Accounts Receivable Securitization facility described below, are available and sufficient to replace funding previously provided by the issuance of commercial paper.

 

In December 2003, Standard and Poor’s lowered CONSOL Energy’s rating of our long-term debt to BB– (13th lowest out of 22 rating categories). Standard and Poor’s defines an obligation rated ‘BB’ as less vulnerable

 

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to nonpayment than other speculative issues. However, the rating indicates that an obligor faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions, which could lead to the obligor’s inadequate capacity to meet its financial commitment on the obligation. The negative sign shows relative standing within the rating category. At the same time, Standard and Poor’s placed CONSOL Energy’s senior unsecured debt rating on CreditWatch with negative implications.

 

In December 2003, Moody’s Investor Service lowered its rating of CONSOL Energy’s long-term debt from Ba1 to Ba3 (13th lowest out of 21 rating categories). The rating remains under review for possible further downgrade. Bonds which are rated “Ba” are considered to have speculative elements; their future cannot be considered as well-assured. Often the protection of interest and principal payments may be very moderate, and thereby not well safeguarded during both good and bad times over the future. Uncertainty of position characterizes bonds in this class. The modifier 3 indicates that the obligation ranks in the lower end of its generic rating category.

 

A security rating is not a recommendation by a rating agency to buy, sell or hold securities. The security rating may be subject to change.

 

In September 2003, CONSOL Energy completed a 364-day $150 million senior secured revolving loan agreement. The new agreement replaced a 364-day bank credit facility of $218 million that expired September 15, 2003. The 364-day $150 million facility under the new agreement was terminated on September 24, 2003 upon receipt of proceeds from the sale by CONSOL Energy of common stock in a private placement. Additionally, in September 2003, the existing multi-year senior revolving credit facility was amended to conform to the terms of the new 364-day agreement, including the provision of collateral to the participating banks consisting of substantially all of CONSOL Energy’s assets, provided that the proceeds of collateral constituting any mineral property or extraction plant, equipment or facility, which may be applied to the principal amount of obligations under the facility is limited to 10% of CONSOL Energy’s consolidated net tangible assets. The multi-year senior credit facility, as amended, provides for an aggregate of $267 million that may be used for letters of credit and borrowings for other corporate purposes. Interest is based at CONSOL Energy’s option, upon the Prime (Base) Rate or London Interbank Offered Rates (LIBOR) plus a spread, which is dependent on its credit rating. The multi-year senior revolving credit facility, as amended, has various covenants, including covenants that limit our ability to dispose of assets and merge with another corporation. We are also required to maintain a ratio of total consolidated indebtedness to twelve month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) of not more than 3.5 to 1.0, measured quarterly. This ratio was 2.72 to 1.0 at December 31, 2003. In addition, we are required to maintain a ratio of twelve months trailing EBITDA to interest expense and amortization of debt of no less than 4.5 to 1.0, measured quarterly. This ratio was 6.89 to 1.0 at December 31, 2003. At December 31, 2003, these two financial covenants would have limited CONSOL Energy’s additional borrowing capacity at an average interest rate of 7% to approximately $180 million. The senior revolving credit facility also has covenants restricting the level of annual capital expenditures to be made by CONSOL Energy. The capital expenditure limit is $293.5 million, $455.0 million and $470.0 million for the twelve months ending December 31, 2003, 2004 and 2005, respectively. Capital expenditures were $290.7 for the twelve months ended December 31, 2003. At December 31, 2003, this facility had approximately $12.3 million letters of credit issued and $65.0 million of borrowings outstanding, leaving approximately $189.7 million of unused capacity. At February 1, 2004, there was approximately $28.5 million of letters of credit issued and $108.0 million of borrowings outstanding against it, leaving approximately $130.3 million of unused capacity.

 

In September 2003, CONSOL Energy sold 11.0 million shares of its common stock in a private placement. The net proceeds of approximately $190 million were placed in an interest bearing restricted cash account, to which CONSOL Energy has limited withdrawal rights, that will be used to support letters of credit issued on behalf of CONSOL Energy to satisfy financial assurance requirements with respect to environmental reclamation and self-insurance employee benefits obligations under various state and federal laws. CONSOL Energy must maintain a balance in the account equal to or greater than 102.5% of the aggregate amount of all letters of credit

 

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issued. At December 31, 2003, 28 letters of credit have been issued that are supported by the restricted cash account. The face amount of the letters of credit total $184.8 million and were issued to:

 

  The United Mine Workers’ of America 1992 Benefit Fund;

 

  The Illinois Industrial Commission, Old Republic Insurance, Travelers Casualty & Surety Co., West Virginia Workers’ Compensation Division, United States Department of Labor, the Commonwealth of Kentucky and Maryland Workers’ Compensation Commission for self insuring workers’ compensation;

 

  Highmark Life and Casualty for employee healthcare insurance;

 

  The Bank of Nova Scotia, Commonwealth of Kentucky, the Commonwealth of Pennsylvania and the West Virginia Department of Environmental Protection for guarantee of performance of environmental obligations; and

 

  Commonwealth of Pennsylvania for guarantee of subsidence bonds.

 

Several of these letters of credit were previously issued under the Senior Revolving Credit Facility.

 

In April 2003, CONSOL Energy and certain of its U.S. subsidiaries entered into a receivables facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable that will provide, on a revolving basis, up to $125 million of short-term funding. CONSOL Energy formed CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, for the sole purpose of buying and selling eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocably and without recourse, sell all of their eligible trade accounts receivable to CNX Funding Corporation. CNX Funding Corporation then sells, on a revolving basis, an undivided percentage interest in the pool of eligible trade accounts receivable to financial institutions and their affiliates, while maintaining a subordinated interest in a portion of the trade receivables. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds are consistent with commercial paper rates plus a charge for administrative services paid to the financial institution. The receivables facility expires in 2006. At December 31, 2003, eligible accounts receivable total approximately $109 million, of which the subordinated retained interest was approximately $1 million. Accordingly, $108 million of accounts receivable were removed from our consolidated balance sheet at December 31, 2003. The proceeds are included in cash flows from operating activities in our consolidated statement of cash flows for the twelve months ended December 31, 2003.

 

CONSOL Energy believes that cash generated from operations and its borrowing capacity will be sufficient to meet its working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments in 2004 and to provide required letters of credit. Nevertheless, the ability of CONSOL Energy to satisfy its working capital requirements, debt service obligations, to fund planned capital expenditures or pay dividends will depend upon its future operating performance, which will be affected by prevailing economic conditions in the coal and gas industries and other financial and business factors, some of which are beyond CONSOL Energy’s control.

 

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with our gas marketers (selling gas under short-term multi-month contract nominations generally not exceeding one year). CONSOL Energy has also entered into five float-for-fixed gas swap transactions and two float-for-collar gas swap transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts resulted in other comprehensive loss of $3.6 million (net of $2.3 million of deferred tax) at December 31, 2003.

 

CONSOL Energy frequently evaluates potential acquisitions. CONSOL Energy has funded acquisitions primarily with cash generated from operations and a variety of other sources, depending on the size of the transaction, including debt financing. There can be no assurance that additional capital resources, including debt financing, will be available to CONSOL Energy on terms which CONSOL Energy finds acceptable, or at all.

 

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Cash Flows (in millions)

 

    

2003

Period


   

2002

Period


    Change

 

Cash flows from operating activities

   $ 381     $ 330     $ 51  

Cash provided by (used in) investing activities

   $ (205 )   $ (340 )   $ 135  

Cash provided by (used in) financing activities

   $ (182 )   $ 6     $ (188 )

 

Cash flows from operating activities have increased primarily due to the following items:

 

  The Accounts Receivable Securitization Facility that will provide, on a revolving basis, up to $125 million of short-term funding. Costs for drawing against this facility are based on commercial paper interest rates. At December 31, 2003, eligible accounts receivable total approximately $109 million, of which the subordinated interest retained by CONSOL Energy was approximately $1 million. Accordingly, $108 million of accounts receivable were removed from the consolidated balance sheet at December 31, 2003;

 

  The receipt of approximately $68 million of refunds in the 2003 period for our black lung excise tax claims and related interest for the years 1994 to 1999 compared to $4 million of refunds with respect to these claims in the 2002 period;

 

  Coal inventories decreased 1.5 million tons in the 2003 period compared to an increase of 1.2 million tons in the 2002 period;

 

  Higher workers’ compensation payments in the 2003 period due to a $21.6 million one-time payment made to the State of West Virginia. The one-time workers’ compensation payment was to settle a dispute with the State of West Virginia Workers’ Compensation Division related to the non-payment of workers’ compensation premiums;

 

  Other post-employment benefits were paid out of operating cash flows in the 2003 period. These benefits were primarily paid from trust assets in the 2002 period and did not impact operating cash flow;

 

  Receivables of $27.4 million in 2003 related to the expected insurance recoveries for two mine fires; and

 

  Decreases in net income as previously discussed.

 

Net cash used in investing activities decreased primarily due to the following items:

 

  Additional proceeds from sales of assets received in the 2003 period compared to 2002 period. The increase in proceeds was due mainly to the sale of CONSOL Energy’s Canadian coal assets and port facilities to Fording Inc. for a note and cash in February 2003. The note was exchanged for 3.2 million units in the Fording Canadian Coal Trust, a newly organized publicly traded trust which acquired the assets of Fording Inc. CONSOL Energy sold the coal trust units in March 2003; and

 

  A decrease in the amounts invested in equity affiliates in the 2003 period compared to the 2002 period. In 2002, CONSOL Energy invested $28 million in a joint-venture with Allegheny Energy Supply Company, LLC, an affiliate of one of our largest coal customers, to build an 88-megawatt, gas-fired electric generating facility in the 2002 period. CONSOL Energy also invested in the Line Creek Mine equity affiliate in the 2002 period. The Line Creek equity affiliate was sold as part of the Canadian asset sale in the first quarter of 2003.

 

Net cash used in financing activities changed primarily due to the following items:

 

  Approximately $246 million in cash received in the 2002 period from the issuance of the 7.875% notes due 2012;

 

  In 2003, payments of all amounts outstanding under the commercial paper program due to CONSOL Energy no longer being able to participate in the commercial paper market, as discussed previously;

 

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  Scheduled long term payments on unsecured notes reduced outstanding debt in the 2002 period with no comparable payment in 2003 period;

 

  Proceeds of approximately $65 million were received from amounts drawn against the Senior Revolving Credit Facility, as discussed previously;

 

  Dividend payments were reduced in the 2003 period compared to the 2002 period due to the reduction of quarterly dividend payments to $0.14 per share beginning with the quarter ended June 30, 2002 from $0.28 per share for each of the previous quarters; and

 

  Approximately $190 million was received in the 2003 period from the sale of 11,000,000 shares of common stock in a private placement in September 2003. The net proceeds of approximately $190 million were subsequently placed in an interest bearing restricted cash account, from which CONSOL

Energy has limited withdrawal rights, that will be used to support letters of credit issued on behalf of CONSOL Energy to satisfy financial assurance requirements of environmental reclamation and self-insurance employee benefits under various state and federal laws.

 

The following is a summary of our significant contractual obligations at December 31, 2003 (in thousands):

 

Payments due by Year

 

    

Within

1 Year


   1-3
Years


   3-5
Years


  

After

5 Years


   Total

Short-term Notes Payable

   $ 68,760    $ —      $ —      $ —      $ 68,760

Long-term Debt

     48,592      10,065      58,105      375,595      492,357

Capital Lease Obligations

     4,738      —        —        —        4,738

Operating Lease Obligations

     17,064      26,885      16,309      7,786      68,044
    

  

  

  

  

Total Contractual Obligations

   $ 139,154    $ 36,950    $ 74,414    $ 383,381    $ 633,899
    

  

  

  

  

 

Additionally, we have long-term liabilities relating to other post employment benefits, work-related injuries and illnesses, defined benefit pension plans, mine reclamation and closure, and other long-term liability costs. We estimate payments, net of any applicable trust reimbursements, related to these items at December 31, 2003 (in thousands) to be:

 

Payments due by Year

 

Within 1 Year

  1-3 Years

  3-5 Years

  Total

$ 358,371   $ 638,461   $ 595,053   $ 1,591,885

 

As discussed in “Critical Accounting Policies” and in the notes to our consolidated financial statements, our determination of these long-term liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Moreover, in particular, for periods after 2003 our estimates may change from the amounts included in the table, and may change significantly, if our assumptions change to reflect changing conditions.

 

Capital expenditures were approximately $291 million in the 2003 period compared to approximately $295 million in the 2002 period. We currently anticipate capital expenditures for the year ending December 31, 2004 to be approximately $340 million to $360 million. However, we may choose to defer certain capital projects in light of operating results and the availability of financing. Capital expenditures for pollution abatement and reclamation are projected to be $3.7 million for the year ending December 31, 2004. Our capital expenditures have been and will be primarily used for replacement of mining and gas equipment, the expansion of mining and gas capacity and projects to improve the efficiency of the mining and gas operations. The projected capital

 

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expenditures for 2004 are not committed and are expected to be funded with cash generated by operations and existing borrowing capacity. In addition, cash requirements to fund employee-related, mine closure and other long-term liabilities included above, along with obligations related to long-term debt, capital and operating leases, are expected to be funded with cash generated by operations and existing borrowing capacity.

 

Debt

 

At December 31, 2003, CONSOL Energy had total long-term debt of $495 million outstanding, including current portion of long-term debt of $53 million. This long-term debt consisted of:

 

  An aggregate principal amount of $248 million ($250 million of 7.875% notes due in 2012, net of $2 million unamortized debt discount). The notes were issued at 99.174% of the principal amount. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and premium, if any, and interest on the notes are guaranteed by most of CONSOL Energy subsidiaries that incur or guarantee certain indebtedness. The notes are senior unsecured obligations and will rank equally with all other unsecured and unsubordinated indebtedness of the guarantors;

 

  An aggregate principal amount of $90 million of unsecured notes which bear interest at fixed rates ranging from 8.21% to 8.28% per annum and are due at various dates between 2004 and 2007;

 

  An aggregate principal amount of $103 million of two series of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at 6.50% per annum and mature in 2010 and 2011;

 

  $17 million aggregate principal amount of borrowings under a term loan facility which allows CONSOL Energy Australia Pty Limited to borrow up to $17 million through March 31, 2004. The borrowed funds must be used for expenditures related to the design, construction, and acquisition of longwall mining equipment and infrastructure upgrades for the longwall mining equipment to enable the extraction of coal using longwall mining methods at Glennies Creek Mine, the joint venture owned 50% by CONSOL Energy Australia Pty Limited. Interest is paid quarterly at a rate of LIBOR plus 1.75%. The principal is payable in equal installments on March 31 and September 30 commencing March 31, 2006 and ending March 31, 2009. This debt was assumed by the purchaser of Glennies Creek Mine on February 25, 2004;

 

  $31 million in advance royalty commitments with an average interest rate of 8.723% per annum;

 

  An aggregate principal amount of $5 million of capital leases with an interest rate of 7.05% to 7.5% per annum; and

 

  An aggregate principal amount of $1 million of variable rate notes with a weighted average interest rate of 3.21% due at various dates ranging from 2004 through 2031.

 

At December 31, 2003, CONSOL Energy had an aggregate principal amount of $65 million of borrowings and approximately $12 million of letters of credit outstanding on the senior revolving credit facility. The senior revolving credit facility is secured by substantially all of our assets, provided that the proceeds of collateral constituting any mineral property or extraction plant, equipment or facility, which may be applied to the principal amount of obligations under the facility is limited to 10% of our consolidated net tangible assets. The senior revolving credit facility provides for an aggregate of $267 million that may be used for letters of credit and borrowings for other corporate purposes. Interest is based at our option, upon the Prime (Base) Rate or London Interbank Offered Rates (LIBOR) plus a spread, which is dependent on our credit rating. The senior revolving credit facility has various covenants, including covenants that limit our ability to dispose of assets and merge with another corporation. We are also required to maintain a ratio of total consolidated indebtedness to twelve month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) of not more than 3.5 to 1.0, measured quarterly. This ratio was 2.73 to 1.0 at December 31, 2003. In addition, we are required to maintain a ratio of twelve months trailing EBITDA to interest expense and amortization of debt of no less than

 

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4.5 to 1.0, measured quarterly. This ratio was 6.87 to 1.0 at December 31, 2003. The senior revolving credit facility also has covenants restricting the level of annual capital expenditures to be made by CONSOL Energy. The capital expenditure limit is $293.5 million, $455.0 million and $470.0 million for the twelve months ending December 31, 2003, 2004 and 2005, respectively. Capital expenditures were $290.7 for the twelve months ended December 31, 2003.

 

A subsidiary of CONSOL Energy also had $4 million aggregate principal amount of short-term debt outstanding under a working capital bank facility utilized by the joint venture operations at the Glennies Creek Mine in Australia. Drawings against this facility are made in Australian dollars and interest is based on the Australian Bank Bills Rate reset monthly. This debt was assumed by the purchaser of Glennies Creek mine on February 25, 2004.

 

Stockholders’ Equity and Dividends

 

CONSOL Energy had stockholders’ equity of $291 million at December 31, 2003 and $162 million at December 31, 2002. Stockholders’ equity increased $190 million in the twelve months ended December 31, 2003 due to the sale of 11,000,000 shares of common stock in a private placement. Stockholders’ equity was reduced by $5 million (net of $3 million of deferred tax) in the twelve months ended December 31, 2003 due to Other Comprehensive Losses. These losses relate primarily to the recognition of minimum pension liability as a result of the negative return on plan assets for non-contributory defined benefit retirement plans. Comprehensive losses (gains) are generally calculated annually and reflect a number of factors including conditions in the stock markets and interest rates. Comprehensive losses have also been recognized for various miscellaneous cash flow hedges, an interest rate swap agreement and an interest rate lock agreement. These transactions were reflected as comprehensive losses and decreased stockholders’ equity by approximately $4 million. See consolidated statements of stockholders’ equity and note 28 of the notes to consolidated financial statements.

 

CONSOL Energy paid ordinary cash dividends of $46 million during the twelve months ended December 31, 2003, $66 million during the twelve months ended December 31, 2002 and $44 million during the six months ended December 31, 2001. The Board of Directors declared a dividend on January 30, 2004 of $0.14 per share of common stock for shareholders of record on February 10, 2004, payable on February 27, 2004. The Board of Directors currently intends to pay quarterly dividends on the common stock. The declaration and payment of dividends by CONSOL Energy is subject to the discretion of the Board of Directors, and no assurance can be given that CONSOL Energy will pay such dividends or any additional dividends in the future. The determination as to the payment of dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, the credit ratings of CONSOL Energy, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. Current outstanding indebtedness of CONSOL Energy does not restrict CONSOL Energy’s ability to pay cash dividends, except that the credit facility would not permit dividend payments in the event of a default.

 

Off-Balance Sheet Transactions

 

CONSOL Energy does not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the notes to the consolidated financial statements included in this prospectus.

 

Inflation

 

Inflation in the United States has been relatively low in recent years and did not have a material impact on CONSOL Energy’s results of operations for the twelve months ended December 31, 2003, twelve months ended December 31, 2002 and the six months ended December 31, 2001.

 

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Recent Accounting Pronouncements

 

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” to expand upon and strengthen existing accounting guidance that addresses when we should include in our financial statements the assets, liabilities and activities of another entity. In general, a variable interest entity is a corporation, partnership, trust, or any other legal structure used for business purposes that either (a) does not have equity investors with voting rights or (b) has equity investors that do not provide sufficient financial resources for the entity to support its activities. Interpretation No. 46 requires a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entities activities, is entitled to receive a majority of the variable interest entities residual returns, or both. The interpretation also requires disclosures about variable interest entities that we are not required to consolidate, but in which we have a significant variable interest. The consolidation requirements of Interpretation No. 46 applied immediately to variable interest entities created after January 31, 2003. Effective October 9, 2003, the FASB elected to defer the effective date until the first fiscal year or interim period that begins after December 15, 2003 for variable interest entities in which an enterprise is acquired before February 1, 2003. As of December 31, 2003, management believes that we do not have any variable interest entities, therefore, there is no impact from the adoption of this standard.

 

In May 2003, Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” was issued and will be effective for CONSOL Energy for all financial instruments entered into or modified after May 31, 2003, and otherwise was effective for CONSOL Energy for the third quarter 2003. This statement affects the classification, measurement and disclosure requirements of certain freestanding financial instruments including mandatorily redeemable shares. As of December 31, 2003, CONSOL Energy does not hold any mandatorily redeemable freestanding financial instruments.

 

Effective December 31, 2003, CONSOL adopted Statement of Financial Accounting Standards (SAFS) No. 132, “Employers’ Disclosure about Pensions and Other Postretirement Benefits—an amendment of SFAB No. 87, 88 and 106.” This standard requires additional disclosure about an employer’s pension plans and postretirement benefit plans such as; the types of plan assets, investment strategy, measurement date, plan obligations, cash flows and components of net periodic benefit cost recognized during the interim periods. See note 19 to the consolidated financial statements included in this pospectus.

 

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Change in Accountants

 

Effective June 5, 2002, the Board of Directors of CONSOL Energy replaced the firm of Ernst & Young LLP as their independent auditor. Effective June 5, 2002, the Board of Directors of CONSOL Energy appointed the firm of PricewaterhouseCoopers LLP to serve as their independent auditor. These actions were taken by the Board of Directors following the recommendation of the Audit Committee.

 

Ernst & Young LLP’s report on the financial statements for CONSOL Energy for the fiscal year ended December 31, 2001 did not contain any adverse opinion or disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles.

 

During CONSOL Energy’s two fiscal years ended December 31, 2001, prior to engaging PricewaterhouseCoopers LLP, there were no disagreements between Ernst & Young LLP and CONSOL Energy on any matter of accounting principles or practices, financial statement disclosures, or auditing scope or procedures which, if not resolved to the satisfaction of Ernst & Young LLP, would have caused them to make reference to the subject matter of the disagreement(s) in connection with its report. There were also no “reportable events” as defined in Item 304(a)(1)(v) of Regulation S-K under the Securities Exchange Act of 1934 or Regulation S-K during CONSOL Energy’s two fiscal years ended December 31, 2001.

 

During CONSOL Energy’s two fiscal years ended December 31, 2001, prior to engaging PricewaterhouseCoopers LLP, CONSOL Energy did not consult PricewaterhouseCoopers LLP with respect to the application of accounting principles to a specified transaction, either completed or proposed; or with respect to the type of audit opinion that might be rendered on CONSOL Energy’s consolidated financial statements; or with respect to any other matters or reportable events as set forth in Items 304(a)(2)(i) and (ii) of Regulation S-K.

 

Quantitative and Qualitative Disclosures About Market Risk

 

In addition to the risks inherent in operations, CONSOL Energy is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CONSOL Energy’s exposure to the risks of changing natural gas prices, interest rates and foreign exchange rates.

 

CONSOL Energy is exposed to market price risk in the normal course of selling natural gas production and to a lesser extent in the sale of coal. CONSOL sells coal under both short-term and long-term contracts with fixed price and/or indexed price contracts that reflect market value. CONSOL Energy uses fixed-price contracts, collar-price contracts and derivative commodity instruments that qualify as cash-flow hedges under Statement of Financial Accounting Standards No. 133 to minimize exposure to market price volatility in the sale of natural gas. Our risk management policy strictly prohibits the use of derivatives for speculative positions.

 

CONSOL Energy has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base. All of the derivative instruments are held for purposes other than trading. They are used primarily to mitigate uncertainty and volatility and cover underlying exposures. CONSOL Energy’s market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.

 

CONSOL Energy believes that the use of derivative instruments along with the risk assessment procedures and internal controls does not expose CONSOL Energy to material risk. The use of derivative instruments could materially affect CONSOL Energy’s results of operations depending on interest rates, exchange rates or market prices. However, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.

 

For a summary of accounting policies related to derivative instruments, see note 1 of notes to the consolidated financial statements.

 

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Sensitivity analyses of the incremental effects on pre-tax income for the twelve months ended December 31, 2003 of a hypothetical 10 percent and 25 percent change in natural gas prices, foreign exchange and interest rates for open derivative instruments as of December 31, 2003 are provided in the following table:

 

     Incremental Decrease in Pre-tax Income Assuming a
Hypothetical Price, Exchange Rate or Interest Rate Change of:


     10%

   25%

     (in millions)

Natural Gas (a)

   $ 20.6    $ 37.8

Foreign Currency (b)

   $ 1.1    $ 2.7

Interest Rates (c)

   $ 0.3    $ 0.7

(a) CONSOL Energy remains at risk for possible changes in the market value of these derivative instruments; however, such risk should be mitigated by price changes in the underlying hedged item. The effect of this offset is not reflected in the sensitivity analyses. CONSOL Energy entered into derivative instruments to convert the market prices related to portions of the 2003 through 2005 anticipated sales of natural gas to fixed prices. The sensitivity analysis reflects an inverse relationship between increases in commodity prices and a benefit to earnings. When commodity prices increase, pretax income decreases. The fair value of these contracts was a loss of $5.4 million (net of $3.5 million deferred tax). We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.
(b) CONSOL Energy uses foreign currency contracts to fix the costs of anticipated Australian dollar capital expenditures. The U.S. dollar notional amount of all foreign currency contracts was $29 million as of December 31, 2003. The sensitivity analysis reflects a direct correlation between increases in foreign currency exchange rates relative to the U.S. dollar and a benefit to earnings. When foreign currency exchange rates increase relative to the U.S. dollar, pre-tax income increases. The fair value of these contracts resulted in $4.9 million of income in the 2003 period.
(c) CONSOL Energy uses interest rate swaps to hedge the interest rate risk exposure of forecasted interest payments on CONSOL Energy Australia Pty Ltd’s, one of CONSOL Energy’s subsidiaries, outstanding variable rate debt. These agreements effectively convert variable rate debt into fixed rate debt. The fair value of these contracts was a loss of $0.8 million (net of $0.5 million deferred tax). The use of these contracts is monitored by CONSOL Energy’s executive management and treasury group.

 

CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The credit worthiness of counterparties is subject to continuing review.

 

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At December 31, 2003, CONSOL Energy had outstanding $495 million aggregate principal amount of debt under fixed-rate instruments and $69 million aggregate principal amount of debt under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to its commercial paper program in which CONSOL Energy was unable to participate after July 2003, and its senior revolving credit facility. At December 31, 2003, CONSOL Energy had no commercial paper outstanding and had an aggregate of $65 million outstanding on the senior revolving credit facility. CONSOL Energy’s commercial paper and senior revolving facility bore interest at a weighted average rate of 2.3% during the twelve months ended December 31, 2003. At December 31, 2002, CONSOL Energy had an aggregate of $203 million in commercial paper outstanding. CONSOL Energy’s commercial paper bore interest at an average rate of 2.1% during the twelve months ended December 31, 2002. A 100 basis-point increase in the average rate for CONSOL Energy’s commercial paper and senior revolving facility would have decreased the twelve months ended December 31, 2003 net income by approximately $0.5 million. A 100 basis-point increase in the average rate for CONSOL Energy’s commercial paper would have decreased CONSOL Energy’s twelve months ended December 31, 2002 net income by approximately $1.8 million. The fair value of CONSOL Energy’s financial instruments is set forth in note 27 and note 28 of the notes to consolidated financial statements.

 

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Almost all of CONSOL Energy’s transactions are denominated in U.S. dollars, and, as a result, it does not have material exposure to currency exchange-rate risks. CONSOL Energy uses foreign currency contracts to fix the costs of anticipated Australian dollar capital expenditures. CONSOL Energy does not have a material exposure to currency exchange-rate risks other than for these foreign currency contracts.

 

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BUSINESS

 

CONSOL Energy’s History

 

We are a multi-fuel energy producer and energy services provider that primarily serves the electric power generation industry in the United States. That industry generates approximately two-thirds of its output by burning coal or gas, the two fuels we produce. At December 31, 2003, we produce high-Btu bituminous coal from 20 mining complexes in the United States and Australia. We also produce pipeline-quality coalbed methane gas from our coal properties in Pennsylvania, Virginia and West Virginia and conventional gas from our properties in Tennessee and Virginia.

 

Recent Events

 

CONSOL Energy incurred a loss before income taxes and before effect of change in accounting principle of $34 million, recognized income tax benefits of $21 million, and recognized a $5 million income adjustment for the effect of change in accounting for mine closing, reclamation and gas well closing costs, resulting in a net loss of $8 million for the twelve months ended December 31, 2003. CONSOL Energy incurred a loss before income taxes of $40 million and recognized income tax benefits of $52 million, resulting in net income of $12 million for the twelve months ended December 31, 2002.

 

Total coal sales for the twelve months ended December 31, 2003 were 64.0 million tons, including our portion of sales by equity affiliates, of which 61.5 million tons sold were produced by CONSOL Energy operations, by our equity affiliates or sold from inventory of our produced coal, including coal sold from inventories and produced by equity affiliates. This compares with total coal sales of 67.3 million tons for the twelve months ended December 31, 2002, of which 64.8 million tons sold were produced by CONSOL Energy operations or sold from inventory of our produced coal, including coal sold from inventories and produced by equity affiliates. The decrease in tons sold primarily is related to lower our coal production in the period-to-period comparison.

 

CONSOL Energy produced 60.4 million tons, including our portion of production at equity affiliates in the 2003 period compared to 66.2 million tons, including our portion of production at equity affiliates in the 2002 period. The decrease in tons produced is primarily due to the closure of the Dilworth, Humphrey and Windsor mines, where economically mineable reserves were depleted in the last quarter of 2002. The decrease was also attributable to the sale of the assets at the Cardinal River and Line Creek mines in February 2003 and the idling of the Rend Lake mine in 2002 due to market conditions. Coal inventories, including our portion of inventories at equity affiliates, were 1.4 million tons at December 31, 2003 compared to 3.0 million tons at December 31, 2002.

 

Sales of coalbed methane gas, including our share of the sales from equity affiliates were 50.0 billion gross cubic feet in the 2003 period compared to 46.6 billion gross cubic feet in the 2002 period. The increased sales volume is primarily due to higher production volumes as a result of our on going drilling program. Our average sales price for coalbed methane gas, including our portion of sales from equity affiliates, was $4.16 per thousand cubic feet in the 2003 period compared to $3.17 per thousand cubic feet in the 2002 period. The increase in average sales price was driven by concerns for levels of natural gas in storage at the beginning of the year, and by concerns over intermediate-term supplies of gas in the United States.

 

In December 2003, CONSOL Energy adopted a shareholder rights plan designed to ensure that all shareholders receive fair value for their common shares in the event of a proposed takeover and to guard against the use of partial tender offers or other coercive tactics to gain control of CONSOL Energy without offering fair value to CONSOL Energy shareholders.

 

In December 2003, Standard and Poor’s lowered CONSOL Energy’s rating of our long-term debt to BB– (13th lowest out of 22 rating categories). Standard and Poor’s defines an obligation rated ‘BB’ as less vulnerable

 

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to nonpayment than other speculative issues. However, the rating indicates that an obligor faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions, which could lead to the obligor’s inadequate capacity to meet its financial commitment on the obligation. The negative sign shows relative standing within the rating category. At the same time, Standard and Poor’s placed CONSOL Energy’s senior unsecured debt rating on CreditWatch with negative implications.

 

In December 2003, Moody’s Investor Service lowered its rating of CONSOL Energy’s long-term debt from Ba1 to Ba3 (13th lowest out of 21 rating categories). The rating remains under review for possible further downgrade. Bonds which are rated “Ba” are considered to have speculative elements; their future cannot be considered as well-assured. Often the protection of interest and principal payments may be very moderate, and thereby not well safeguarded during both good and bad times over the future. Uncertainty of position characterizes bonds in this class. The modifier 3 indicates that the obligation ranks in the lower end of its generic rating category.

 

A security rating is not a recommendation by a rating agency to buy, sell or hold securities. The security rating may be subject to change.

 

In January, 2004, CONSOL Energy announced that it intended to sell the stock in its wholly owned subsidiary CNX Australia Pty Limited to certain affiliates of AMCI, Inc. for $27.5 million, the assumption of approximately $21 million of debt, and associated interest rate swaps and foreign currency hedges. CNX Australia Pty Limited, through its wholly owned subsidiary CONSOL Energy Australia Pty Limited, owns a 50% interest in the Glennies Creek Mine in New South Wales, Australia with its joint venture partner Maitland Main Collieries Pty Limited, an affiliate of AMCI, Inc. Agreements were finalized on February 25, 2004 and are expected to result in a pre-tax gain of approximately $13 million.

 

In January 2004, a Special Committee of the Board of Directors of CONSOL Energy completed its investigation of allegations against certain directors and officers of CONSOL Energy contained in an anonymous letter sent to the United States Securities and Exchange Commission. The Special Committee found no evidence of fraud or malfeasance and no evidence to suggest that CONSOL Energy’s publicly issued financial statements were incorrect.

 

In January 2004, CONSOL Energy’s Board of Directors elected three new independent members to the Board. They were: William E. Davis, a power industry executive; William P. Powell, an investment banker; and Joseph T. Williams, a former oil and gas industry executive. In February 2004, CONSOL Energy’s Board of Directors elected Raj Gupta, a former oil and gas industry executive, as an independent member of the Board.

 

Loveridge Mine began full production in the beginning of March 2004. Loveridge Mine experienced a fire in February 2003 that delayed the development of a new underground area that was originally to begin production in 2003.

 

In February 2004, CONSOL Energy’s former majority shareholder, RWE A.G., closed on a previously announced private placement sale of its remaining 16.6 million shares of CONSOL Energy common stock. On September 23 and 24, 2003, RWE closed on a previously announced sale of 14.1 million shares of CONSOL Energy common stock. On the same dates, CONSOL Energy closed on a previously announced sale of 11.0 million primary shares of its common stock, increasing the total shares of common stock outstanding to 89.8 million and reduced RWE’s initial majority interest from 73.6% to 48.9%. On October 9, 2003, RWE closed on the sale of 27.3 million shares of CONSOL Energy common stock. That sale reduced RWE’s ownership to 16.6 million shares, or 18.5%.

 

In February 2004, as a result of the sale of the remaining shares of CONSOL Energy common stock held by RWE AG and pursuant to the terms of the Placement Agreement, dated September 18, 2003, by and among CONSOL Energy, Friedman, Billings, Ramsey & Co., Inc. and RWE Rheinbraun AG, the remaining two

 

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directors representing RWE AG, Berthold Bonekamp and Dr. Rolf Zimmerman, resigned from the CONSOL Energy Board of Directors. Also in February 2004, Raj K. Gupta, a former oil and gas industry executive, was elected to the board of directors of CONSOL Energy. He will serve until the next election of directors at the annual meeting of shareholders.

 

Industry Segments

 

CONSOL Energy has two principle business units: Coal and Gas. The principal activities of the Coal unit are mining, preparation and marketing of steam coal, sold primarily to power generators, and metallurgical coal, sold to steel and coke producers. The Coal unit includes four reportable segments. These reportable segments are Northern Appalachian, Central Appalachian, Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines). For the year ended December 31, 2003, the Northern Appalachian aggregated segment includes the following mines: Shoemaker, Blacksville #2, Robinson Run, McElroy, Bailey, Enlow Fork and Mine 84. For the year ended December 31, 2003, the Central Appalachian aggregated segment includes the following mines: Jones Fork, Mill Creek and Wiley-Mill Creek. For the year ended December 31, 2003, the Metallurgical aggregated segment includes the following mines: Buchanan, Amonate and V.P. #8. The Other Coal segment includes our purchased coal activities, idled mine cost, coal segment business units not meeting aggregation criteria as well as various activities assigned to the coal segment but not allocated to each individual mine. The principal activity of the Gas unit is to produce pipeline quality methane gas for sale primarily to gas wholesalers. Financial information concerning industry segments, as defined by generally accepted accounting principles, for the twelve months ended December 31, 2003 and 2002, the six months ended December 31, 2001, and the fiscal year ended June 30, 2001 is included in note 30 of notes to consolidated financial statements.

 

Coal Operations

 

Mining Complexes

 

At December 31, 2003, CONSOL Energy had 20 mining complexes located in the United States and Australia, including a 50% interest in the Glennies Creek mine located in Australia. In January 2004, CONSOL Energy announced that it intended to sell the stock in its wholly owned subsidiary CNX Australia Pty Limited to certain affiliates of AMCI, Inc. for $27.5 million, the assumption of approximately $21 million of debt, and associated interest rate swaps and foreign currency hedges. CNX Australia Pty Limited, through its wholly owned subsidiary CONSOL Energy Australia Pty Limited, owns a 50% interest in the Glennies Creek Mine in New South Wales, Australia with its joint venture partner Maitland Main Collieries Pty Limited, an affiliate of AMCI, Inc. Agreements were finalized on February 25, 2004 and are expected to result in a pre-tax gain of approximately $13 million.

 

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The following map provides the location of CONSOL Energy’s operations by region:

 

LOGO

 

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The following table provides the location of each of CONSOL Energy’s mining complexes at December 31, 2003 and 2002, the amount of coal reserves and a summary of the characteristics of the assigned and accessible coal reserves associated with each of its mining complexes. In February 2003, we sold our Cardinal River and Line Creek mines.

 

CONSOL ENERGY MINING COMPLEXES

 

Average Quality and Recoverable Reserves

 

Mine/Reserve


  Location

  Reserve Class

  Coal Seam

  Average
Seam
Thickness
(feet)


  Average Coal Quality (As-Received) (1)

  Recoverable Reserves (12/31/03) (2)

  Recoverable
Reserves
(tons in
millions)
12/31/2002


         

Moisture

(%)


 

Sulfur

(%)


  Heat Value
(Btu/lb)


 

Owned

(%)


   

Leased

(%)


   

Tons

(in millions)


 

ASSIGNED—OPERATING

                                               

Northern Appalachia

                                               

Enlow Fork

  Enon, PA   Assigned   Pittsburgh   4.94   6.0   1.63   13,267   67 %   33 %   58.3   68.2
        Accessible   Pittsburgh   5.40   6.0   1.92   13,219   81 %   19 %   165.5   165.5

Bailey

  Enon, PA   Assigned   Pittsburgh   5.64   6.0   2.00   13,223   11 %   89 %   96.1   93.1
        Accessible   Pittsburgh   5.75   6.0   2.47   13,176   49 %   51 %   142.6   74.6

Mine 84

  Eighty Four, PA   Assigned   Pittsburgh   5.61   6.0   1.49   13,394   62 %   38 %   49.3   53.3
        Accessible   Pittsburgh   5.38   6.0   1.94   13,324   88 %   12 %   58.5   58.5

McElroy

  Glen Easton, WV   Assigned   Pittsburgh   5.83   5.7   3.03   13,166   100 %   0 %   174.5   177.0

Shoemaker

  Moundsville, WV   Assigned   Pittsburgh   5.54   7.3   3.40   12,864   100 %   0 %   45.2   70.0
        Accessible   Pittsburgh   5.55   7.3   2.96   12,930   100 %   0 %   5.2   15.6

Loveridge

  Fairview, WV   Assigned   Pittsburgh   7.91   5.4   2.27   13,215   100 %   0 %   13.0   13.3
        Accessible   Pittsburgh   7.39   5.5   2.81   13,347   100 %   0 %   93.9   107.0

Robinson Run

  Shinnston, WV   Assigned   Pittsburgh   7.16   6.0   3.16   13,278   69 %   31 %   28.4   34.0
        Accessible   Pittsburgh   6.90   6.7   3.19   13,158   32 %   68 %   113.6   125.8

Blacksville 2

  Wana, WV   Assigned   Pittsburgh   6.65   6.0   2.53   13,315   100 %   0 %   34.5   40.0
        Accessible   Pittsburgh   6.83   5.6   2.45   13,360   98 %   2 %   60.8   120.3

Mahoning Valley

  Cadiz, OH   Assigned   Pittsburgh   4.34   6.7   2.08   11,517   100 %   0 %   5.2   1.4

Central Appalachia

                                               

Buchanan

  Mavisdale, VA   Assigned   Pocahontas 3   5.66   6.3   0.68   14,057   7 %   93 %   43.8   42.5
        Accessible   Pocahontas 3   6.09   6.3   0.65   14,006   8 %   92 %   81.6   94.5

VP-3

  Vansant, VA   Assigned   Pocahontas 3   4.63   6.6   0.73   14,097   0 %   100 %   7.8   7.9

VP-8

  Rowe, VA   Assigned   Pocahontas 3   5.24   9.0   0.77   13,581   2 %   98 %   2.4   6.5

Mill Creek Complex

  Deane, KY   Assigned   Multiple   3.70   6.5   1.29   13,298   94 %   6 %   20.2   8.5
        Accessible   Multiple   4.42   5.5   1.18   12,261   100 %   0 %   0.7   17.7

Jones Fork Complex

  Mousie, KY   Assigned   Multiple   3.57   7.0   1.00   12,925   37 %   63 %   34.5   15.7
        Accessible   Multiple   3.48   7.2   .95   12,673   61 %   39 %   4.9   26.7

Amonate Complex

  Amonate, VA   Assigned   Multiple   3.35   6.7   0.71   13,072   24 %   76 %   9.4   7.8

Elk Creek Complex

  Emmett, WV   —     Multiple   —     —     —     —     —       —       —     10.8

 

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Mine/Reserve


  

Location


  

Reserve Class


  

Coal Seam


  Average
Seam
Thickness
(feet)


          Recoverable
Reserves
(tons in
millions)
12/31/2002


            

Average Coal Quality

(As-Received) (1)


  Recoverable Reserves
(12/31/03) (2)


 
             Moisture
(%)


  Sulfur
(%)


  Heat Value
(Btu/lb)


 

Owned

(%)


   

Leased

(%)


   

Tons

(in millions)


 

Illinois Basin

                                                  

Rend Lake

   Sesser, IL    Assigned    Illinois 6   6.77   11.8   1.21   12,149   12 %   88 %   21.3   21.3
          Accessible    Illinois 6   5.99   11.8   1.47   12,082   87 %   13 %   33.7   33.7

Ohio 11

   Morganfield, KY    Assigned    Kentucky 11   4.44   11.6   2.87   11,877   0 %   100 %   8.3   8.3
          Accessible    Kentucky 11   4.44   11.5   2.88   11,890   0 %   100 %   2.2   2.2

Western U.S.

                                                  

Emery

   Emery Co., UT    Assigned    Ferron I   7.50   7.0   0.73   11,803   80 %   20 %   21.5   21.7
          Accessible    Ferron A   8.82   7.0   0.93   11,683   47 %   53 %   12.3   12.3

Australia (New South Wales) (3)

                                             

Glennies Creek

   Hunter Valley, NSW    Assigned    Middle Liddel   7.68   7.0   0.45   12,778   0 %   100 %   9.6   10.2

Total Assigned—Operating

                                             

Assets Sold in February, 2003

                                             

Cardinal River

   Hinton, AL    Assigned    Jewell   —     —     —     —     —       —       —     0.7

Line Creek

   Sparwood, BC    Assigned    Multiple   —     —     —     —     —       —       —     30.7

Total Assigned Operating and Accessible

                                             1,458.8   1,597.3

(1) We show average coal quality as it is received by the customer, including our estimation of the amount of moisture in the coal when shipped. The average coal quality we report may be based either on a processed, or washed, basis, or a non-processed, or raw, basis, depending upon the most generally intended market for the coal. Because out-of-seam dilution is not considered in our reserve calculation or because the diluting rock is assumed to be removed during processing, we do not include out-of-seam dilution adjustments to the quality values that we report.
(2) We calculate our proven and probable reserve tons by identifying the area in which mineable coal exists, the thickness of the coal seam or seams we control and average coal density as reported by our laboratory based on core samples we receive from our field drilling. We then adjust the reserve calculation to account for the amount of coal that our experience indicates will not be recovered during the mining process and for losses that occur if the coal is processed after it is mined. Our reserve calculations do not include an adjustment for any moisture that may be added to the coal during mining or processing—commonly referred to as excess moisture—nor do the calculations generally include adjustments for dilution from rock lying immediately above or below the coal seam—referred to as out-of-seam dilution— that may be extracted during the mining process. Where out-of-seam dilution is included, we adjust the expected recovery of coal from the processing plant to remove the effect of dilution from the reserve calculation.
(3) Reported reserves represent our 50% interest in the Glennies Creek Mine, which was sold on February 25, 2004.

 

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Excluded from the table above are approximately 112.5 million tons of reserves at December 31, 2003 that are assigned to projects that have not produced coal in 2003 or 2002. These assigned reserves are in the Northern Appalachia (Pennsylvania, Ohio and northern West Virginia) and Central Appalachia (Virginia, southern West Virginia and Eastern Kentucky) regions. These reserves are approximately 84% owned and 16% leased. Average quality on an “as-received” basis range from 5.4% to 7.0% moisture content, 0.54% to 4.05% sulfur content and 12,568 to 13,778 heat value (British thermal units per pound).

 

CONSOL Energy assigns coal reserves to each of its mining complexes. The amount of coal we assign to a mining complex generally is sufficient to support mining through the duration of its current mining permit. Under federal law, we must renew our mining permits every five years.

 

In addition, our mining complexes may have access to additional reserves that have not yet been assigned. We refer to these reserves as accessible. Accessible reserves are proven and probable unassigned reserves that can be accessed by an existing mining complex, utilizing the existing infrastructure of the complex to mine and to process the coal in this area. Mining an accessible reserve does not require additional capital spending beyond that required to extend or to continue the normal progression of the mine, such as the sinking of airshafts or the construction of portal facilities.

 

Some reserves may be accessible by more than one mining complex because of the proximity of many of our mining complexes to one another. In the table above, the accessible reserves indicated for a mining complex is based on our review of current mining plans and reflects our best judgment as to which mining complex is most likely to utilize the reserve.

 

Assigned and unassigned coal reserves are proven and probable reserves which are either owned in fee or leased. The leases have terms extending up to 30 years and generally provide for renewal through the anticipated life of the associated mine. These renewals are exercisable by the payment of minimum royalties. Under current mining plans all reported reserves will be mined out within the period of existing leases or within the time period of assured lease renewal periods.

 

At December 31, 2003, the Loveridge Mine was in development and is scheduled to begin production in early March 2004. At December 31, 2003, Rend Lake, Emery, Elk Creek, VP-3 and Ohio 11 complexes were idle. These mines are anticipated to remain idle until market conditions support reopening. In February 2003, we sold our Cardinal River and Line Creek Mines in western Canada. During 2002, CONSOL Energy ceased production at the Dilworth, Humphrey, Meigs, Muskingum and Windsor Mines due to the depletion of economically recoverable reserves.

 

Coal Reserves

 

At December 31, 2003, CONSOL Energy had an estimated 4.2 billion tons of proven and probable reserves. Reserves are the portion of the proven and probable tonnage that meet CONSOL Energy’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels.

 

Proven reserves are reserves for which:

 

(a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling; and

 

(b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

 

Consol Energy’s calculations of proven reserves generally do not rely on isolated points of observation. Small pods of measured reserves are not considered; continuity of observation points over a large area is

 

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necessary for proven status. Our estimates for proven reserves have the highest degree of geologic assurance. Estimates of rank, quality and quantity for these reserves have been computed from points of observation which are equal to or less than one half mile apart, except for our properties within the Pittsburgh 8 seam for which points of observation are 3,000 feet or less apart because of the well known continuity of that seam. The sites for measuring thickness of proven reserves are so closely spaced, and the geologic character is so well defined, that the average thickness, area, extent, size, shape and depth of coalbeds are well established.

 

Our reserve estimates are predicated on information obtained from our ongoing exploration drilling and in-mine channel sampling programs. Data including elevation, thickness, and, where samples are available, the quality of the coal from individual drill holes and channel samples are input into a computerized geological database. The information derived from the geological database is then combined with data on ownership or control of the mineral and surface interests to determine the extent of the reserves in a given area.

 

Probable reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but for which the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation. Estimates for probable coal reserves have a moderate degree of geologic assurance and have been computed by us from points of observation which are between 0.5 and 1.5 miles apart, except for our properties within the Pittsburgh 8 seam for which points of observation are 3,000 feet or less because of the well known continuity of that seam. The sites for measuring thickness of proven reserves are so closely spaced, and the geologic character is so well defined, that the average thickness, area, extent, size, shape and depth of coalbeds are well established.

 

Information with respect to proven and probable coal reserves has been determined by CONSOL Energy’s geologists and mining engineers and has not been reviewed by independent experts.

 

Drill hole spacing for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey), except for our properties within the Pittsburgh 8 seam for which points of observation are 3,000 feet or less because of the well-known continuity of that seam. The sites for measuring thickness of proven reserves are so closely spaced, and the geologic character is so well defined, that the average thickness, area, extent, size, shape and depth of coalbeds are well established.

 

CONSOL Energy’s coals fall within the range of commercially marketed coals in the United States. The marketability of coal depends on its value-in-use for a particular application, and this is affected by coal quality, including, for example, sulfur content, ash and heating value. Modern power plant boiler design aspects can compensate for coal quality differences that occur. Therefore, any of CONSOL Energy’s coals can be marketed for power generation.

 

All mining reserves have their required permits or governmental approvals, or there is a very high probability that these approvals will be secured.

 

CONSOL Energy’s reserves are located in northern Appalachia (54%), central Appalachia (10%), the mid-western United States (21%), the western United States (11%), and in western Canada and Australia (4%) at December 31, 2003.

 

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The following table sets forth our unassigned proven and probable reserves by region:

 

CONSOL Energy—UNASSIGNED Recoverable Coal Reserves as of 12/31/03

 

     Range of Average Product Quality (As-Received) (1)

   Recoverable Reserves 12/31/03 (2)

  

Recoverable
Reserves

(tons in millions)
12/31/2002


Coal Producing Region


  

Moisture

(%)


  

Sulfur

(%)


  

Heat Value

(Btu/lb)


  

Owned

(%)


  

Leased

(%)


  

Tons

(in millions)


  

Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)

   4.5 –   8.5    0.69 – 3.70    10,362 – 13,514    90    10    1,032.7    842.6

Central Appalachia (Virginia, Southern West Virginia, Eastern Kentucky)

   6.3 –   7.2    0.51 – 1.11    12,186 – 14,215    55    45    167.3    176.0

Illinois Basin (Illinois, Western Kentucky, Indiana)

   11.3 – 12.0    0.77 – 2.89    11,481 – 12,106    33    67    817.7    824.4

Western U.S. (Montana, Wyoming, Utah)

   23.7 – 28.0    0.19 – 0.45    8,563 –   9,404    58    42    439.4    439.4

Western Canada (Alberta)

   8.0    0.42 – 0.51    12,419 – 12,911    —      100    129.1    159.9

Total

                  60    40    2,586.2    2,442.3

(1) We show coal quality as it is received by the customer, including our estimation of the amount of moisture in the coal when shipped. The coal quality we report may be based either on a processed, or washed, basis, or a non-processed, or raw, basis, depending upon the most generally intended market for the coal. Because out-of-seam dilution is not considered in our reserve calculation or because the diluting rock is assumed to be removed during processing, we do not include out-of-seam dilution adjustments to the quality values that we report.
(2) We calculate our reserve tons by identifying the area in which mineable coal exists, the thickness of the coal seam or seams we control and average coal density as reported by our laboratory based on core samples we receive from our field drilling. We then adjust the reserve calculation to account for the amount of coal that our experience indicates will not be recovered during the mining process and for losses that occur if the coal is processed after it is mined. Our reserve calculations do not include an adjustment for any moisture that may be added to the coal during mining or processing – commonly referred to as excess moisture – nor do the calculations generally include adjustments for dilution from rock lying immediately above or below the coal seam – referred to as out-of-seam dilution – that may be extracted during the mining process. Where out-of-seam dilution is included, we adjust the expected recovery of coal from the processing plant to remove the effect of dilution from the reserve calculation.

 

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The following table summarizes our proven and probable reserves as of December 31, 2003 by region and type of coal or sulfur content (sulfur content per million British thermal unit). Proven and probable reserves include both assigned and unassigned reserves. Amounts for unassigned reserves are net amounts based on various recovery rates reflecting CONSOL Energy’s experience in recovering coal from seams. In reporting unassigned reserves, CONSOL Energy has assumed approximately 60% recovery of in-place coal for reserves that can be mined using the longwall method, approximately 50% recovery of in-place coal for reserves that will be mined using other underground methods and approximately 90% recovery for surface mines.

 

The table classifies bituminous coal as high volatile A, B and C. High volatile A, B and C bituminous coals are classified on the basis of heat value. The table also classifies bituminous coals as medium and low volatile which are classified on the basis of fixed carbon and volatile matter. Coal is ranked by the degree of alteration it has undergone since the initial deposition of the organic material. The lowest ranked coal, lignite, has undergone less transformation than the highest ranked coal, anthracite. From the lowest to the highest rank, the coals are: lignite; sub-bituminous; bituminous and anthracite. The ranking is determined by measuring the fixed carbon to volatile matter ratio and the heat content of the coal. As rank increases, the amount of fixed carbon increases, volatile matter decreases, and heat content increases. Bituminous coals are further characterized by the amount of volatile matter present. Bituminous coals with high volatile matter content are also ranked. High volatile “A” bituminous coals have a higher heat content than high volatile “C” bituminous coals. These characterizations of coal allow a user to predict the behavior of a coal when burned in a boiler to produce heat or when it is heated in the absence of oxygen to produce coke for steel production.

 

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CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES

BY PRODUCING REGION AND PRODUCT (IN MILLIONS OF TONS) AS OF

DECEMBER 31, 2003

 

     < 1.20 lbs

    > 1.20 < 2.50 lbs

    > 2.50 lbs

    Total

    Percentage
By Region


 
     S02/MMBtu

    S02/MMBtu

    S02/MMBtu

     

By Region


   Low
Btu


    Med
Btu


    High
Btu


    Low
Btu


    Med
Btu


    High
Btu


    Low
Btu


    Med
Btu


    High
Btu


     

Northern Appalachia:

                                                                  

Metallurgical:

                                                                  

High Vol A Bituminous

   —       —       —       —       —       187.2     —       —       —       187.2     4.5 %

Steam:

                                                                  

High Vol A Bituminous

   —       49.4     —       —       10.0     107.7     38.5     50.4     1,789.5     2,045.5     49.2 %

Low Vol Bituminous

   —       —       —       —       —       15.9     —       —       —       15.9     0.4 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   —       49.4     —       —       10.0     310.8     38.5     50.4     1,789.5     2,248.6     54.1 %

Central Appalachia:

                                                                  

Metallurgical:

                                                                  

High Vol A Bituminous

   —       7.3     18.6     —       —       2.1     —       —       —       28.0     0.7 %

Med Vol Bituminous

   1.1     2.1     70.5     —       —       —       —       —       —       73.7     1.8 %

Low Vol Bituminous

   —       —       147.0     2.3     —       —       —       —       —       149.3     3.6 %

Steam:

                                                                  

High Vol A Bituminous

   20.5     24.7     10.0     33.7     4.0     54.5     —       —       15.4     162.8     3.9 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   21.6     34.1     246.1     36.0     4.0     56.6     —       —       15.4     413.8     10.0 %

Midwest—Illinois Basin:

                                                                  

Steam:

                                                                  

High Vol B Bituminous

   —       —       —       —       68.5     55.0     36.6     437.4     35.6     633.1     15.2 %

High Vol C Bituminous

   —       —       —       —       158.1     —       92.0     —       —       250.1     6.0 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   —       —       —       —       226.6     55.0     128.6     437.4     35.6     883.2     21.2 %

Northern Powder River Basin:

                                                                  

Steam:

                                                                  

Subbituminous B

   —       —       252.8     —       —       —       —       —       —       252.8     6.1 %

Subbituminous C

   —       186.6     —       —       —       —       —       —       —       186.6     4.5 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   —       186.6     252.8     —       —       —       —       —       —       439.4     10.6 %

Utah—Emery Field:

                                                                  

High Vol B Bituminous

   —       —       —       —       33.8     —       —       —       —       33.8     0.8 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   —       —       —       —       33.8     —       —       —       —       33.8     0.8 %

Western Canada:

                                                                  

Metallurgical:

                                                                  

Med Vol Bituminous

   18.7     86.1     —       —       —       —       —       —       —       104.8     2.5 %

Low Vol Bituminous

   22.5     1.8     —       —       —       —       —       —       —       24.3     0.6 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   41.2     87.9     —       —       —       —       —       —       —       129.1     3.1 %

Hunter Valley, Australia (1)

                                                                  

Metallurgical:

                                                                  

High Vol A Bituminous

   —       9.6     —       —       —       —       —       —       —       9.6     0.2 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   —       9.6     —       —       —       —       —       —       —       9.6     0.2 %
    

 

 

 

 

 

 

 

 

 

 

Total Company

   62.8     367.6     498.9     36.0     274.4     422.4     167.1     487.8     1,840.5     4,157.5     100.0 %
    

 

 

 

 

 

 

 

 

 

 

Percent of Total

   1.5 %   8.8 %   12.0 %   0.9 %   6.6 %   10.2 %   4.0 %   11.7 %   44.3 %   100.0 %      
    

 

 

 

 

 

 

 

 

 

     

(1) Reported reserves represent our 50% interest in the Glennies Creek Mine, which was sold on February 25, 2004.

 

63


Table of Contents

CONSOL ENERGY PROVEN AND PROBABLE COAL RECOVERABLE RESERVES

BY PRODUCT (000 TONS) AS OF DECEMBER 31, 2003

 

The following table classifies bituminous coal as high volatile A, B and C. High volatile A, B and C bituminous coals are classified on the basis of heat value. The table also classifies bituminous coals as medium and low volatile which are classified on the basis of fixed carbon and volatile matter.

 

     < 1.20 lbs

    > 1.20 – < 2.50 lbs

    ³ 2.50 lbs

    Total

   

Percentage

By Product


 
     S02/MMBtu

    S02/MMBtu

    S02/MMBtu

     

By Product


   Low
Btu


    Med
Btu


    High
Btu


    Low
Btu


    Med
Btu


    High
Btu


    Low
Btu


    Med
Btu


    High
Btu


     

Metallurgical:

                                                                  

High Vol A Bituminous

   —       16.9     18.6     —       —       189.3     —       —       —       224.8     5.4 %

Med Vol Bituminous

   19.8     88.2     70.5     —       —       —       —       —       —       178.5     4.3 %

Low Vol Bituminous

   22.5     1.8     147.0     2.3     —       —       —       —       —       173.6     4.2 %
    

 

 

 

 

 

 

 

 

 

 

Total Metallurgical

   42.3     106.9     236.1     2.3     —       189.3     —       —       —       576.9     13.9 %

Steam:

                                                                  

High Vol A Bituminous

   20.5     74.1     10.0     33.7     14.0     162.2     38.5     50.4     1,804.9     2,208.3     53.1 %

High Vol B Bituminous

   —       —       —       —       102.3     55.0     36.6     437.4     35.6     666.9     16.0 %

High Vol C Bituminous

   —       —       —       —       158.1     —       92.0     —       —       250.1     6.0 %

Low Vol Bituminous

   —       —       —       —       —       15.9     —       —       —       15.9     0.4 %

Subbituminous B

   —       —       252.8     —       —       —       —       —       —       252.8     6.1 %

Subbituminous C

   —       186.6     —       —       —       —       —       —       —       186.6     4.5 %
    

 

 

 

 

 

 

 

 

 

 

Total Steam

   20.5     260.7     262.8     33.7     274.4     233.1     167.1     487.8     1,840.5     3,580.6     86.1 %
    

 

 

 

 

 

 

 

 

 

 

Total

   62.8     367.6     498.9     36.0     274.4     422.4     167.1     487.8     1,840.5     4,157.5     100.0 %
    

 

 

 

 

 

 

 

 

 

 

Percent of Total

   1.5 %   8.8 %   12.0 %   0.9 %   6.6 %   10.2 %   4.0 %   11.7 %   44.3 %   100.00 %      
    

 

 

 

 

 

 

 

 

 

     

 

The following table categorizes the relative Btu values (low, medium and high) for each of CONSOL Energy’s producing regions in Btus per pound of coal.

 

Region