Form 10-K

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K

 

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

 

For the fiscal year ended December 31, 2003;

 

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                         

 

Commission file number: 001-14901

 


 

CONSOL ENERGY INC.

(Exact name of registrant as specified in its charter)

 

Delaware   51-0337383

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

Consol Plaza

1800 Washington Road

Pittsburgh, Pennsylvania 15241

(Address of principal executive offices including zip code)

 

Registrant’s telephone number including area code: 412-831-4000

 


 

Securities registered pursuant to Section 12(b) of the Act:

 

Name of exchange on which registered


 

Title of each Class


New York Stock Exchange

  Common Stock ($.01 par value)

 

No securities are registered pursuant to Section 12(g) of the Act.

 


 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2)    Yes x    No  ¨

 

The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 2003, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price of the common stock on the New York Stock Exchange on such date was $472,350,186.

 

The number of shares outstanding of the registrant’s common stock as of February 29, 2004 is 89,934,151 shares.

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

Portions of the Company’s Proxy Statement for the Annual Meeting of Shareholders to be held on April 27, 2004,

are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III

 



TABLE OF CONTENTS

 

          Page

PART I

    

Item 1.

   Business    5

Item 2.

   Properties    35

Item 3.

   Legal Proceedings    36

Item 4.

   Submission of Matters to a Vote of Security Holders    36

PART II

    

Item 5.

   Market for Registrant’s Common Equity and Related Stockholder Matters    37
     Executive Officers of CONSOL Energy    38

Item 6.

   Selected Financial Data    39

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operation    42

Item 7A.

   Quantitative and Qualitative Disclosures About Market Risk    85

Item 8.

   Financial Statements and Supplementary Data    88

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosures    160

Item 9A.

   Controls and Procedures    160

PART III

    

Item 10.

   Directors and Executive Officers of the Registrant    161

Item 11.

   Executive Compensation    161

Item 12.

   Security Ownership of Certain Beneficial Owners and Management    161

Item 13.

   Certain Relationships and Related Transactions    161

Item 14.

   Principal Accounting Fees and Services    161

PART IV

    

Item 15.

   Exhibits, Financial Statement Schedules and Reports on Form 8-K    162

SIGNATURES

    

 

 

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FORWARD-LOOKING STATEMENTS

 

We are including the following cautionary statement in this Report on Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of us. With the exception of historical matters, the matters discussed in this Report on Form 10-K are forward-looking statements (as defined in Section 21E of the Exchange Act) that involve risks and uncertainties that could cause actual results to differ materially from projected results. In addition to other factors and matters discussed elsewhere in this Report on Form 10-K, these risks, uncertainties and contingencies include, but are not limited to, the following:

 

  effects of the amount of our debt compared to stockholders’ equity and recent changes in our credit ratings;

 

  results of an informal SEC 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;

 

  the continued incurrence of losses in future periods;

 

  a reduction in deferred tax assets could materially reduce our operating results and stockholders’ equity and possibly preclude dividend payments;

 

  our inability to obtain substantial additional financing necessary in order to fund our operations, capital expenditures and to meet our other obligations;

 

  our ability to comply with restrictions imposed by our senior credit facility;

 

  increased cost and expense related to the downgrading of our credit ratings;

 

  a loss of our competitive position because of the competitive nature of the coal and gas markets;

 

  a decline in prices we receive for our coal and gas affecting our operating results and cash flows;

 

  the inability to produce a sufficient amount of coal to fulfill our customers’ requirements which could result in our customers initiating claims against us;

 

  overcapacity in the coal or gas industry impairing our profitability;

 

  reliance on customers extending existing contracts or entering into new long-term contracts for coal;

 

  reliance on major customers;

 

  a decline in our customers’ coal requirements;

 

  the creditworthiness of our customer base declining;

 

  our ability to identify suitable acquisition candidates and to successfully finance, consummate the acquisition of, and integrate these candidates as part of our acquisition strategy;

 

  disputes with customers concerning coal contracts resulting in litigation;

 

  the risks inherent in coal mining being subject to unexpected disruptions, including geological conditions, equipment failure, fires, accidents and weather conditions which could cause our results to deteriorate;

 

  uncertainties in estimating our economically recoverable coal and gas reserves;

 

  risks in exploring for and producing gas;

 

  our failure to remove and dispose of water from coal beds may hamper our ability to produce gas in commercial quantities;

 

  the disruption of rail, barge and other systems which deliver our coal, or pipeline systems which deliver our gas;

 

3


  the effects of government regulation;

 

  obtaining governmental permits and approvals for our operations;

 

  coal users switching to other fuels in order to comply with various environmental standards related to coal combustion;

 

  the effects of mine closing, reclamation and certain other liabilities;

 

  federal, state and local authorities regulating our gas production activities;

 

  deregulation of the electric utility industry having unanticipated effects on our industry;

 

  new legislation resulting in restrictions on coal use;

 

  federal and state laws imposing treatment, monitoring and reporting obligations on us;

 

  management’s ability to correctly estimate and accrue for contingent liabilities;

 

  excessive lump sum payments made to retiring salaried employees pursuant to our defined benefit pension plan;

 

  increased exposure to workers’ compensation and black lung benefit liabilities;

 

  the outcome of various asbestos litigation cases;

 

  our ability to comply with laws or regulations requiring that we obtain surety bonds for workers’ compensation and other statutory requirements.

 

  results of one or more purported class action lawsuits against us and certain of our officers alleging that the defendants issued false and misleading statements to the public and seeking damages and costs;

 

  the anti-takeover effects of our rights plan could prevent a change of control;

 

  decline in our share price due to the increase in shares eligible for sale; and

 

  our ability to service debt and pay dividends is dependent upon us receiving distributions from our subsidiaries.

 

4


Item 1. 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. 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, we operate 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.

 

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.

 

5


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 company 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 company produced coal, including coal sold from inventories and produced by equity affiliates. The decrease in tons sold primarily is related to lower company 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 the company 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 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

 

6


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 the company 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 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 principal 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 the Company’s 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

 

7


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 included as Item 7 in Part II of this Annual Report on Form 10-K, as amended.

 

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.

 

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

 

LOGO

 

8


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

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

 

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(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.

 

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

 

10


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 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.

 

11


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.

 

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

 

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

 

Coal Producing Region


  

Range of Average Product
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)


  

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.

 

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.

 

12


CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES

BY PRODUCING REGION AND PRODUCT (IN MILLIONS OF TONS) AS OF DECEMBER 31, 2003

 

By Region


   £1.20 lbs

    > 1.20 < 2.50 lbs

    > 2.50 lbs

    Total

    Percentage
By Region


 
   S02/MMBtu

    S02/MMBtu

    S02/MMBtu

     
   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.

 

13


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.

 

By Product


   £1.20 lbs

    > 1.20 < 2.50 lbs

    > 2.50 lbs

    Total

    Percentage
By Product


 
   S02/MMBtu

    S02/MMBtu

    S02/MMBtu

     
   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


   Low

   Medium

   High

Northern, Central Appalachia, Canada and Australia

   < 12,500    12,500-13,000    > 13,000

Midwest

   < 11,600    11,600-12,000    > 12,000

Northern Powder River Basin

   <   8,400    8,400-8,800    >   8,800

Colorado and Utah

   < 11,000    11,000-12,000    > 12,000

 

CONSOL Energy’s reserve estimates are based on geological, engineering and market data assembled and analyzed by our staff of geologists and engineers located at individual mines, operations offices and at its principal office. The reserve estimates and general economic criteria upon which they are based are reviewed and adjusted annually to reflect production of coal from the reserves, analysis of new engineering and geological data, changes in property control, modification of mining methods and other factors. Reserve information, including the quantity and quality of reserves, coal and surface ownership, lease payments and other information relating to CONSOL Energy’s coal reserve and land holdings, is maintained through a system of interrelated computerized databases developed by CONSOL Energy.

 

CONSOL Energy’s reserve estimates are predicated on information obtained from its ongoing exploration drilling and in-mine channel sampling programs. Data including elevation, thickness, 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. None of our coal reserves have been reviewed by independent experts.

 

14


Compliance Compared to Non-Compliance Coal

 

Coals are sometimes characterized as compliance or non-compliance coal. The phrase compliance coal, as it is commonly used in the coal industry, refers to compliance only with sulfur dioxide emissions standards and indicates that when burned, the coal will produce emissions that will meet the current standard without further cleanup. A coal considered a compliance coal for meeting sulfur dioxide standards may not meet an emission standard for a different pollutant such as mercury. Moreover, the term compliance coal is always used with reference to the then current regulatory limit. If the regulatory limit for sulfur dioxide is made more restrictive, it is likely to reduce significantly the amount of coal that can be labeled compliance. Currently, a compliance coal will meet the power plant emission standard of 1.2 pounds of sulfur dioxide per million British thermal units of fuel consumed. At December 31, 2003, 0.9 billion tons, or 22%, of our coal reserves met the current standard as a compliance coal. It is possible that no coal would be considered compliance if emission standards were restricted to a level that requires emissions-control technology to be used regardless of the sulfur content of the coal.

 

As a result of a 1998 court decision forcing the establishment of mercury emissions for power plants, the Environmental Protection Agency, on January 30, 2004, proposed a new regulatory program for controlling mercury. CONSOL Energy coals have mercury contents typical for their rank and location (approximately 0.05-0.1 parts mercury per million British thermal unit). Because most CONSOL Energy coals have high heating values, they have lower mercury contents (on a pound per British thermal unit basis) than lower rank coals at a given mercury concentration. Eastern bituminous coals tend to produce a greater proportion of flue gas mercury in the ionic or oxidized form (which is captured by scrubbers installed for sulfur control) than sub-bituminous coal, including coals produced in the Powder River Basin. High rank coals also may be more amenable to other methods of controlling mercury emissions, such as by carbon injection. In the case of mercury, the determination of the existence of a compliance coal for mercury will be based on an analysis of the requirements of the new program and may result in a coal that is compliant for sulfur dioxide standards, but non-compliant for mercury.

 

Production

 

In the twelve months ended December 31, 2003, 97% of CONSOL Energy’s production came from underground mines and 3% from surface mines. Where the geology is favorable and where reserves are sufficient, CONSOL Energy employs longwall mining systems in its underground mines. For the twelve months ended December 31, 2003, 89% of its production came from mines equipped with longwall mining systems. Underground longwall systems are highly mechanized, capital intensive operations. Mines using longwall systems have a low variable cost structure compared with other types of mines and can achieve high productivity levels compared with those of other underground mining methods. Because CONSOL Energy has substantial reserves readily suitable to these operations, CONSOL Energy believes that these longwall mines can increase capacity at low incremental cost.

 

15


The following table shows the production, in millions of tons, for CONSOL Energy’s mines in the twelve months ended December 31, 2003, 2002 and 2001, the location of each mine, the type of mine, the type of equipment used at each mine and the year each mine was established or acquired by us. The table includes information for five mines, Dilworth, Humphrey, Meigs, Muskingum and Windsor, that closed during 2002 because of reserve depletion. In February 2003, we sold our Cardinal River and Line Creek Mines in western Canada. The table excludes idled complexes that have not produced in any of the periods presented.

 

Mine


 

Location


  Mine
Type


  Mining
Equipment


  Transportation

 

Tons Produced

(in millions)


  Year
Established
or Acquired


          2003

  2002

  2001

 

Northern Appalachia

                               

Enlow Fork

  Enon, Pennsylvania   U   LW/CM   R R/B   9.9   9.6   10.3   1990

Bailey

  Enon, Pennsylvania   U   LW/CM   R R/B   9.4   9.7   10.3   1984

McElroy

  Glen Easton, West Virginia   U   LW/CM   B   6.3   4.7   6.6   1968

Robinson Run

  Shinnston, West Virginia   U   LW/CM   R CB   5.7   5.0   4.9   1966

Mine No. 84

  Eighty Four, Pennsylvania   U   LW/CM   R R/B T   4.0   4.0   1.4   1998

Blacksville 2

  Wana, West Virginia   U   LW/CM   R R/B T   5.4   4.8   5.0   1970

Dilworth(1)

  Rices Landing, Pennsylvania   U   LW/CM   B   —     3.6   4.7   1984

Shoemaker

  Moundsville, West Virginia   U   LW/CM   B   3.8   3.4   4.1   1966

Loveridge(2)

  Fairview, West Virginia   U   LW/CM   R T   —     —     1.1   1956

Humphrey(1)

  Maidsville, West Virginia   U   CM   R   —     0.5   0.7   1956

Mahoning Valley

  Cadiz, Ohio   S   S/L   R T   0.7   0.3   0.5   1974

Meigs(1)

  Point Rock, Ohio   U   LW/CM   R   —     0.4   1.9   2001

Muskingum(1)

  Cumberland, Ohio   S   D   R   —     —     0.5   2001

Windsor(1)

  West Liberty, West Virginia   U   LW/CM   R   —     1.3   0.7   2001

Central Appalachia

                               

Buchanan

  Mavisdale, Virginia   U   LW/CM   R   4.7   4.1   4.5   1983

VP-8

  Rowe, Virginia   U   LW/CM   R   1.9   2.2   2.3   1993

Mill Creek(3)

  Deane, Kentucky   U/S   CM   R   3.7   3.5   3.6   1994

Jones Fork(3)

  Mousie, Kentucky   U/S   CM   R T   3.0   4.0   4.9   1992

Amonate(3)

  Amonate, Virginia   U   CM   R   0.7   0.5   0.5   1925

Illinois Basin

                               

Rend Lake(4)

  Sesser, Illinois   U   LW/CM   R T   —     1.7   2.0   1986

Western U.S.

                               

Emery(4)

  Emery County, Utah   U   LW/CM   T   0.2   —     —     1945

Western Canada

                               

Cardinal River(5)

  Hinton, Alberta, Canada   S   S/L   R   0.1   1.2   1.7   1969

Line Creek(5)

  Sparwood, British Columbia, Canada   S   S/L   R   0.2   1.7   1.5   2000

Australia

                               

Glennies Creek(6)

  Hunter Valley, New South Wales, Australia   U   LW/CM   R   0.6   0.1   —     2001

S = Surface

U = Underground

LW = Longwall

CM = Continuous Miner

S/L = Stripping Shovel and Front End Loaders

D = Dragline and Dozers

R = Rail

B = Barge

R/B = Rail to Barge

T = Truck

CB = Conveyor Belt

(1) Production at the complex ceased during the twelve months ended December 31, 2002, due to the depletion of economically recoverable reserves.
(2) Complex was in development at December 31, 2003.
(3) Amonate, Mill Creek and Jones Fork complexes include operations by independent mining contractors.
(4) Rend Lake and Emery mines were idled for all or part of the years ended December 31, 2003 and 2002 due to market conditions.
(5) Sold in February 2003.
(6) CONSOL Energy’s 50% interest in the Glennies Creek Mine was sold on February 25, 2004.

 

16


The amounts shown for tons produced for all periods presented by Cardinal River, Line Creek and Glennies Creek actually represent 50% of the production of each mine, reflecting our 50% interest in each mine.

 

Our sales of bituminous coal were at an average sales price per ton produced as follows:

 

    

Twelve Months

Ended
December 31,


   Six Months
Ended
December 31,
   Twelve Months
Ended
June 30,
     2003

   2002

   2001

   2001

Average Sales Price for Ton Produced

   $ 27.61    $ 26.76    $ 25.02    $ 23.93

 

Expansion projects are planned at several of our mining complexes. These projects include the expansion of McElroy Mine that is intended to increase capacity from about 7 million tons per year to about 11 million tons per year. The new preparation plant at McElroy, put into service in September 2002, was the first phase of the project. Currently, the remaining expansion is expected to be complete in the third quarter of 2004. A project also has begun to complete a preparation plant expansion at the shared Bailey and Enlow facility. The expansion of the preparation plant will allow production capacity at these two mines to be increased from about 20 million tons per year to over 22 million tons per year. This expansion currently is expected to be complete by the end of 2004.

 

Beginning in 2001, Mine 84 encountered a sandstone intrusion in the coal seam that extended across several longwall coal panels. Because sandstone is harder than coal, mining advance rates are slowed for both longwall and continuous mining machines. In 2003, Mine 84 production continued to be lower than anticipated because of the adverse geological conditions encountered periodically and associated mechanical problems. In addition, Mine 84 experienced a conveyor belt fire in early 2003. The fire was extinguished and the conveyor belt repaired allowing longwall operations to resume in February 2003. A new employee and material access portal will be completed at Mine 84 in the second quarter of 2004. The portal will reduce the time for employees and supplies to reach active work areas.

 

The Loveridge Mine, which was on long-term idle status in 2002 due to market conditions, experienced a mine fire in early 2003. A different area of the mine was entered in April and development production resumed in the third quarter of 2003. Longwall operations commenced in early March 2004.

 

A roof fall on the Bailey Mine Main-West beltline interrupted production in fourth quarter of 2003. The belt was repaired in early November 2003. Longwall mining in the area the beltline serves will be complete by the end of the first half of 2004. A new 7,500-ton underground bunker was completed at Bailey in late 2003. This system will support a new longwall that was also installed in late 2003.

 

A new longwall was installed in the Robinson Run Mine in third quarter of 2003. In addition, in the first half of 2003, equipment enhancements were made to the Robinson Run coal processing facility to increase productivity. A new coal preparation plant is projected to replace this facility in late 2006.

 

A new production slope was completed in late 2003 at the Jones Fork complex in East Kentucky. The project will allow the decommissioning of several miles of underground conveyor belt system and allow simultaneous mining of selected adjacent reserves by contractors.

 

In 2003, a new mining area was established near our Amonate coal processing facility. The Miles Branch area began full production in July 2003 producing high quality, mid-volatile metallurgical coal. Miles Branch produced approximately 80 thousand tons in the year ended December 31, 2003.

 

In March 2004, the agreement to sell Emery Mine was terminated due to the potential buyer not securing the requisite financing. CONSOL Energy will be evaluating ownership versus other potential sales to third parties.

 

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%

 

17


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.

 

Title to coal properties that we lease or purchase and the boundaries of such properties are verified, at the time we lease or acquire the properties, by law firms retained by us. Consistent with industry practice, abstracts and title reports are reviewed and updated approximately five years prior to planned development or mining of the property. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine such reserves could be adversely affected.

 

The following table sets forth, with respect to properties that we lease to other coal operators, the total annual royalty tonnage mined from our properties, the total acreage leased and the amount of income (net of related expenses) we received from royalty payments from other operators for the twelve months ended December 31, 2003, 2002 and 2001.

 

Year


  

Total Royalty
Tonnage

(in thousands)


  

Total
Coal

Acreage
Leased


  

Total Royalty
Income

(in thousands)


2003

   17,633    244,109    $ 6,266

2002

   17,680    202,033    $ 7,451

2001

   18,050    182,203    $ 5,723

 

Royalty tonnage leased to third parties is not included in the amounts of produced tons that we report. Proven and probable reserves do not include reserves attributable to properties that we lease to third parties.

 

CONSOL Energy operates approximately 23% of the United States longwall mining systems.

 

The following table ranks the 20 largest underground mines in the United States by tons of coal produced in calendar year 2002, the latest information available at the time of filing.

 

MAJOR U.S. UNDERGROUND COAL MINES—2002

In millions of tons

 

Mine Name


  

Operating Company


   Production

Bailey

   CONSOL Energy    9.7

Enlow Fork

   CONSOL Energy    9.6

SUFCO

   Canyon Fuel Company    7.6

Twentymile

   Twentymile Coal Company    7.6

Cumberland

   RAG Cumberland Resources Corp.    6.6

Emerald

   RAG Emerald Resources Corp.    6.6

West Elk

   Arch Coal Inc.    6.6

Galatia

   The American Coal Co.    6.3

Bowie No. 2

   Bowie Resources, LTD    5.4

Federal No. 2

   Eastern Associated Coal Corp.    5.0

Robinson Run

   CONSOL Energy    5.0

Blacksville 2

   CONSOL Energy    4.8

McElroy

   CONSOL Energy    4.7

Dotiki

   Webster County Coal LLC    4.5

Mountaineer

   Arch Coal, Inc.    4.2

Buchanan

   CONSOL Energy    4.1

Jones Fork

   CONSOL Energy    4.0

Deer Creek

   Energy West Mining Co.    4.0

Eighty Four Mine

   CONSOL Energy    4.0

Shoal Creek

   Drummond Company, Inc.    4.0

Source: National Mining Association

 

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Marketing and Sales

 

We sell coal produced by our mining complexes and additional coal that is purchased by us for resale from other producers. We maintain United States sales offices in Atlanta, Philadelphia and Pittsburgh and an overseas office in Brussels, Belgium. In addition, we sell coal through agents, brokers and unaffiliated trading companies. In the twelve months ended December 31, 2003, we sold 64 million tons of coal, including our percentage of sales in equity affiliates, 88% of which was sold in domestic markets. Our direct sales to domestic electricity generators represented 70% of our total tons sold in the twelve months ended December 31, 2003. Including equity affiliate sales, we had approximately 155 customers in the twelve months ended December 31, 2003. During the twelve months ended December 31, 2003, Allegheny Energy accounted for 14% of our total revenue.

 

Coal Contracts

 

We sell coal to customers under arrangements that are the result of both bidding procedures and extensive negotiations. We sell coal for terms that range from a single shipment to multi-year agreements for millions of tons. 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. The pricing mechanisms under our multiple-year agreements typically consist of contracts with one or more of the following pricing mechanisms:

 

  Fixed price contracts; or

 

  Annually negotiated prices that reflect market conditions at the time; or

 

  Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices or, in some cases, pass-through of actual cost changes.

 

A few contracts have features of several contract types, such as provisions that allow for renegotiation of prices on a limited basis within a base-price-plus-escalation agreement. Such re-opener provisions allow both the customer and us an opportunity to adjust prices to a level close to then current market conditions. Each contract is negotiated separately, and the triggers for re-opener provisions differ from contract to contract. Some of our existing contracts with re-opener provisions adjust the contract price to market price at the time the re-opener provision is triggered. Market price generally is based on recent published transactions for similar quantities and quality of coal. Re-opener provisions could result in early termination of a contract or in requirements that certain volumes be purchased if the parties were to fail to agree on price and other terms that may be subject to renegotiation.

 

The following table sets forth, as of February 25, 2004, the total tons of coal CONSOL Energy is obligated to deliver under agreements during calendar years 2004 through 2008.

 

    

Tons of Coal to be Delivered

(in millions of nominal tons)


     2004

   2005

   2006

   2007

   2008

(1)

   69.6    34.2    22.5    10.8    5.4

(2)

   0.3    9.7    8.9    9.7    7.5
    
  
  
  
  
     69.9    43.9    31.4    20.5    12.9

(1) Obligations to deliver coal at predetermined prices.
(2) Obligations to deliver coal at prices to be determined by mutual agreement of the parties, including some agreements which contain predetermined price ranges.

 

  The foregoing table does not include an aggregate of 3.5 million tons that we may be required to deliver during the calendar years 2004 through 2008 upon exercise of rights of customers under executed contracts to buy more coal at predetermined prices

 

19


We routinely engage in efforts to renew or extend contracts scheduled to expire. Although there are no guarantees that contracts will be renewed, we have been successful in the past in renewing or extending contracts.

 

Contracts also typically contain force majeure provisions allowing for the suspension of performance by the customer or us for the duration of specified events beyond the control of the affected party, including labor disputes. Some contracts may terminate upon continuance of an event of force majeure for an extended period, which are generally three to twelve months. Contracts also typically specify minimum and maximum quality specifications regarding the coal to be delivered. Failure to meet these conditions could result in substantial price reductions or termination of the contract, at the election of the customer. Although the volume to be delivered under a long-term contract is stipulated, we, or the buyer may vary the timing of delivery within specified limits or the buyer in some instances may vary the volume.

 

Many contracts provide the opportunity to adjust the contract prices. Contract prices may be adjusted as often as quarterly based upon indices which are pre-negotiated. Many of our recently negotiated contracts have had terms, generally no longer than three to five years. Exceptions to this are two agreements with FirstEnergy. A seventeen year, 76.5 million ton coal agreement entered into in January 2003, provides for annual shipments of 4.5 million tons to FirstEnergy Generation Corp., a subsidiary of FirstEnergy Corp., primarily from McElroy Mine. An eighteen year, 52 million ton coal agreement entered into in February 2004 provides for shipments in the first year of 1 million tons, and thereafter, annual shipments of 3 million tons, primarily from the Bailey and Enlow Fork mines. This agreement includes similar provisions as the 76.5 million ton agreement entered into in January 2003. The agreement includes a price re-opener provision every three years, beginning in 2005. If CONSOL Energy and FirstEnergy do not agree on price at that time, the contract can be terminated by either party.

 

Distribution

 

Coal is transported from CONSOL Energy’s mining complexes to customers by means of railroad cars, river barges, trucks, conveyor belts or a combination of these means of transportation. Currently, the Robinson Run Mine transports coal to customers by conveyor belt. Currently, the McElroy and Shoemaker complexes ship coal to customers by means of river barges. Currently trucks are used to transport coal from the Loveridge, Mine 84, Jones Fork, Blacksville and Mahoning Valley complexes. Currently, the Enlow Fork, Bailey, Mine No. 84, Robinson Run, Loveridge, Blacksville, Buchanan, Mill Creek, Jones Fork, VP-8 and Amonate complexes primarily transport coal to customers by rail.

 

We employ transportation specialists who negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines, terminal operators, ocean vessel brokers and trucking companies.

 

We own five towboats and six harbor boats and a fleet of approximately 300 barges to serve customers along the Ohio and Monongahela Rivers. The barge operation allows us to control delivery schedules and serves as temporary floating storage for coal where land storage is unavailable. Approximately 31% of the coal that we produced was shipped on the inland waterways in the twelve months ended December 31, 2003.

 

Competition

 

The United States coal industry is highly competitive, with numerous producers in all coal producing regions. CONSOL Energy competes against other large producers and hundreds of small producers in the United States and overseas. The largest producer is estimated by the 2003 National Mining Association Survey to have produced approximately 18% (based on tonnage produced) of the total United States production in 2002. The U.S. Department of Energy reported 1,426 active coal mines in the United States in 2002, the latest year for which government statistics are available. Demand for our coal by our 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;

 

20


  coal quality;

 

  transportation costs from the mine to the customer; and

 

  the reliability of supply.

 

Continued demand for CONSOL Energy’s coal and the prices that CONSOL Energy obtains are affected by demand for electricity, environmental and government regulation, technological developments and the availability and price of competing coal and alternative fuel supplies. 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.

 

Gas Operations

 

CONSOL Energy produces coalbed methane, which is pipeline quality gas that resides in coal seams. In the eastern United States, conventional natural gas fields typically are located in various types of sedimentary formations at depths ranging from 2,000 to 15,000 feet. Exploration companies often put their capital at risk by searching for gas in commercially exploitable quantities at these depths. By contrast, gas in the coal seams that CONSOL Energy drills or anticipates drilling is typically in formations less than 2,500 feet deep which are usually better defined than deeper formations. CONSOL Energy believes that this contributes to lower exploration costs than those incurred by producers that operate in deeper, less defined formations.

 

Nearly all of our gas production currently is from operations in southwestern Virginia. In this region, we operated 1,403 wells, 806 miles of gathering lines and various compression stations at December 31, 2003. Our southwestern Virginia operations control approximately 235,000 acres of gas rights. At December 31, 2003, we reported 983 billion cubic feet of net proved reserves of gas, of which approximately 34.3% is developed. Our December 2003 average daily gross production in this region is approximately 142 million cubic feet per day.

 

We have been developing gas production in southwestern Pennsylvania and northern West Virginia by gathering gas currently being vented to the atmosphere by our mines in the area. In this region, our December 2003 average daily gross production was approximately 3.9 million cubic feet per day. At December 31, 2003, we reported 19.6 billion cubic feet of net proved reserves of gas, of which approximately 79% is developed. We expect to expand production of gas in this area by drilling additional production wells into the coal seams that we own or control.

 

We have also been developing gas production in the Tennessee area through a 50% joint venture. In this area, our 50% portion of December 2003 average daily gross production was approximately 0.3 million cubic feet per day. At December 31, 2003, our portion of proved net gas reserves for this area was 1.6 billion cubic feet, of which 53.3% were developed.

 

CONSOL Energy has not filed reserve estimates with any federal agency.

 

21


Drilling

 

The total average daily gross rate of production controlled by CONSOL Energy during the twelve months ended December 31, 2003, was 139.1 million cubic feet. During the twelve months ended December 31, 2003, December 31, 2002, the six months ended December 31, 2001, and the twelve months ended June 30, 2001, we drilled in the aggregate, 251, 197, 141, and 203 development wells, respectively, all of which were productive. The net number of wells for those periods was approximately 244, 194, 141, and 157 wells, respectively. To date, we have not had any dry development wells. The following table illustrates the wells referenced above by geographic region:

 

Development Wells

 

    

For the Twelve Months

Ended December 31,


   For the Six
Months Ended
December 31,
2001


  

For the Twelve
Months Ended
June 30,

2001


     2003

   2002

     
     Gross

   Net

   Gross

   Net

   Gross

   Net

   Gross

   Net

Virginia

   237    237    191    191    141    141    203    157

Tennessee

   14    7    6    3    —      —      —      —  

 

During the twelve months ended December 31, 2003 and 2002, the six months ended December 31, 2001 and the twelve months ended June 30, 2001, we drilled in the aggregate 52, 34, 21 and 6 exploratory wells, respectively. The net number of wells for those periods was 36, 25, 19 and 0, respectively. To date, we have not had any dry exploration wells, although some of the 2002 and 2003 wells are still being evaluated or are awaiting completion. Nine of the Northern West Virginia and Southwest Pennsylvania wells are also awaiting completion. The following table illustrates the exploratory wells by geographic region:

 

Exploration Wells

 

    

For the Twelve Months

Ended December 31,


   For the Six
Months Ended
December 31,
2001


  

For the Twelve
Months Ended
June 30,

2001


     2003

   2002

     
     Gross

   Net

   Gross

   Net

   Gross

   Net

   Gross

   Net

Virginia

   19    16    15    15    10    10    2    —  

Northern West

                                       

Virginia/Southwest Pennsylvania

   7    7    1    1    8    8    4    —  

Tennessee

   26    13    18    9    3    1.5    —      —  

 

Production

 

The following table sets forth CONSOL Energy’s net revenue interest production for the periods indicated.

 

    

Twelve Months

Ended
December 31,


  

Six Months
Ended
December 31,

2001


  

Twelve
Months
Ended
June 30,

2001


     2003

   2002

     

Coalbed methane (in millions of cubic feet)

   44,421    41,269    17,399    29,754

 

Water produced from our Virginia operations, which represents 95% of the total water produced by our gas operations, is injected into injection wells. Water from our Northern West Virginia/Southwest Pennsylvania operations is hauled to an independent treatment facility where it is treated and discharged.

 

22


Average Sales Prices and Lifting Costs

 

The following table sets forth the average sales price and the average lifting cost for all of our gas production for the periods indicated. Lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization. See Note 33 of Notes to Consolidated Financial Statements.

 

     Average Gas Sales Price and Lifting Cost
for the


     Twelve Months
Ended
December 31,


  

Six Months
Ended

December 31,

2001


  

Twelve
Months
Ended
June 30,

2001


     2003

   2002

     

Average gas sales price (per thousand cubic feet)

   $ 4.31    $ 3.17    $ 2.63    $ 5.19

Average lifting cost (per thousand cubic feet)

   $ 0.46    $ 0.40    $ 0.53    $ 0.42

 

Productive Wells and Acreage

 

The following table sets forth, at December 31, 2003, the number of CONSOL Energy’s producing wells, developed acreage and undeveloped acreage.

 

     Gross

   Net

Producing Wells

   1,525    1,512

Developed Acreage

   112,971    112,451

Undeveloped Acreage

   378,034    262,718

 

We drilled 251 development wells in the twelve months ended December 31, 2003, of which 35 wells were in process at December 31, 2003. Nearly all of our development wells and acreage are located in southwestern Virginia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied.

 

We currently plan to drill approximately 300 wells in the twelve-month period ending December 31, 2004. Two hundred of these wells are proposed to be conventional coalbed methane wells drilled into coal seams not yet mined. Sixty of the remaining wells are to be drilled into mine areas to produce gob gas, which is methane gas that has collected in abandoned areas of underground coal mines. Thirty-nine of the projected wells are conventional gas wells. Compared to coalbed methane wells, conventional gas wells put capital at a higher risk due to the potential for unsuccessful drilling. As such, the success rate of conventional gas wells may not reflect that of our coalbed methane drilling program. Two of these wells are proposed to be horizontal wells. Horizontal drilling techniques are designed to increase productivity and recovery rates in coal seams not conducive to vertical fracturing.

 

Sales

 

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 contracts generally not exceeding one year. Within the terms of the individual sales confirmations executed under the master marketing contracts, at December 31, 2003, we were obligated to deliver 45.0 billion cubic feet during the twelve-month period ending December 31, 2004. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, we have not failed to deliver quantities required under contract. We also have a gas-balancing agreement with TCO Interstate Pipeline. This agreement is in accordance with the Council of Petroleum Accountants Societies (COPAS) definition of producer imbalances, whereby the operator controls the physical production and delivery of gas to a transporter. Contracted quantities of gas rarely equal physical deliveries. As the operator, CONSOL Energy is responsible for monitoring this imbalance and requesting adjustments to contracted volumes as circumstances warrant. The imbalance agreement

 

23


is managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken and paid for by the purchaser. The imbalance amounts, for both volumes and dollars, were insignificant at December 31, 2003.

 

The hedging strategy and information regarding derivative instruments used are outlined in item 7A, “Qualitative and Quantitative Disclosures About Market Risk”, and in Note 28 to the Consolidated Financial Statements.

 

Distribution

 

Our gas operations in Virginia have built separate gathering systems in their gas fields to deliver gas to market. While each gathering system begins at the individual wellhead, gas from wells is transported to market in each case by the Cardinal States Gathering Company’s major gathering system. Cardinal States Gathering Company is a wholly owned subsidiary which operates two major gathering systems. The first gathering system is a 50-mile, 16-inch gathering system that is capable of transporting 100 million cubic feet of gas per day. This gathering system has processing and compression facilities and connects with a Columbia Transmission pipeline located in Mingo County, West Virginia. The second gathering system is a 30-mile, 20-inch gathering system capable of transporting 150 million cubic feet of gas per day. This gathering system also connects with a Columbia Transmission gathering system in Wyoming County, West Virginia.

 

Gas Reserves

 

CONSOL Energy’s gas reserves are either owned or leased. Proved gas reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recovered in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of a 1/8 royalty ownership. Reported reserves include 50% of the reserves for Pocahontas Gas Partnership as of June 30, 2001. CONSOL Energy owned a 50% interest in Pocahontas Gas Partnership until August 2001, when CONSOL Energy acquired the remaining 50% interest. Proved developed and proved undeveloped gas reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and undeveloped gas reserves are defined by the Securities and Exchange Commission Rule 4.10(a) of Regulation S-X.

 

    

Net Gas Reserves

(millions of cubic feet)


     As of December 31,

   As of
June 30,
     2003

   2002

   2001

   2001

Estimated proved developed reserves

   353,778    330,246    364,143    234,386

Estimated proved undeveloped reserves

   650,603    630,259    659,236    442,765

Total estimated proved developed and undeveloped reserves

   1,004,381    960,505    1,023,379    677,151

 

24


Discounted Future Net Cash Flows

 

The following table shows, for CONSOL Energy’s net estimated proved developed and undeveloped reserves, its estimated future net cash flows and total standardized measure of discounted, at 10%, future net cash flows:

 

    

Discounted Future Net Cash Flows

($ in thousands)


     As of December 31,

   As of
June 30,


     2003

   2002

   2001

   2001

Future net cash flows (net of income tax)

   $ 2,708,797    $ 2,037,696    $ 901,343    $ 551,607

Total standardized measure of discounted future net cash flows (net of income tax)

   $ 1,011,186    $ 735,181    $ 345,826    $ 189,156

Total standardized measure of pre-tax discounted future net cash flow

   $ 1,556,866    $ 1,089,900    $ 432,148    $ 288,070

 

 

Competition

 

CONSOL Energy’s gas operations primarily compete regionally in the northeastern United States. Competition throughout the country is regionalized. CONSOL Energy believes that the gas market is highly fragmented and not dominated by any single producer. CONSOL Energy believes that several of its competitors have devoted far greater resources than it has to gas exploration and development. CONSOL Energy believes that competition within its market is based primarily on price and the proximity of gas fields to customers.

 

Other

 

CONSOL Energy provides other services both to its own operations and to others. These include terminal services (including break bulk, general cargo and warehouse services), river and dock services, industrial supply services, coal waste disposal services, land resource services, research and development services and power generation.

 

Power Generation

 

In March 2002, we entered into 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. This facility was completed in June 2002 at a total cost of approximately $56 million, of which CONSOL Energy paid approximately $28 million, and is used for meeting peak load demands. The facility is in southwest Virginia and uses coalbed methane gas that we produce. In the twelve months ended December 31, 2003 and 2002, the facility operated for a total of 17,610 and 34,540 megawatt hours, respectively, and did not have a significant effect on earnings in either period.

 

Land Resources

 

CONSOL Energy is developing property assets previously used primarily to support its coal operations or which currently are not utilized. CONSOL Energy expects to increase the value of its property assets by:

 

  developing surface properties for commercial uses other than coal mining or gas development when the location of the property is suitable;

 

  deriving royalty income from coal, oil and gas reserves CONSOL Energy owns but does not intend to develop;

 

25


  deriving income from the sustainable harvesting of timber on land CONSOL Energy owns; and

 

  deriving income from the rental of surface property for agricultural and non-agricultural uses.

 

CONSOL Energy’s objective is to improve the return on these assets without detracting from its core businesses and without significant additional capital investment.

 

Industrial Supply Services

 

Fairmont Supply Company, a CONSOL Energy subsidiary, is a general-line distributor of mining and industrial supplies in the United States. Fairmont Supply has 12 customer service centers nationwide. Fairmont Supply also provides integrated supply procurement and management services. Integrated supply procurement is a materials management strategy that utilizes a single, full-line distributor to minimize total cost in the maintenance, repair and operating supply chain. Fairmont Supply offers value-added services including on-site stores management and procurement strategies.

 

Fairmont Supply provides mine supplies to CONSOL Energy’s mining operations. Approximately 56% of Fairmont Supply’s sales in the twelve months ended December 31, 2003, were made to CONSOL Energy’s mines.

 

Terminal Services

 

In the twelve months ended December 31, 2003, approximately 2.7 million tons of coal were shipped through CONSOL Energy’s exporting terminal in the Port of Baltimore. Approximately 90% of the tonnage shipped was produced by CONSOL Energy coal mines. The terminal can either store coal or load coal directly into vessels from rail cars. It is also one of the few terminals in the United States served by two railroads, Norfolk Southern and CSX Transportation.

 

On August 14, 2002, CONSOL Energy, through its subsidiary CNX Marine Terminals Inc., began operations as a general cargo and warehouse provider in Baltimore for shipments of metal, forest products and other bulk cargo.

 

River and Dock Services

 

CONSOL Energy’s river operation, located in Elizabeth, Pennsylvania, transports coal from our mines with river loadout facilities along the Monongahela and Ohio Rivers in northern West Virginia and southwestern Pennsylvania to customers along these rivers. The river operation employs five company-owned towboats, six harbor boats and approximately 300 barges. In the twelve months ended December 31, 2003, our river vessels transported 7.9 million tons of our coal.

 

CONSOL Energy provides dock services at Kellogg Dock, located on the Mississippi River in southern Illinois, and Alicia Dock, located on the Monongahela River in Fayette County, Pennsylvania, north of the Dilworth mine. Kellogg Dock was idle for most of the twelve months ended December 31, 2003. CONSOL Energy transfers coal from rail cars to barges for customers that receive coal on the river system.

 

Coal Waste Disposal Services

 

CONSOL Energy operates an ash disposal facility on a 61-acre site in northern West Virginia to handle ash residues for coal customers that are unable to dispose of ash on-site at their generating facilities. This facility became operational in early 1994. The ash disposal facility can process 200 tons of material per hour. CONSOL Energy has a long-term contract with a cogeneration facility to supply coal and take the residual fly ash and bottom ash. Bottom ash is sold locally for road construction and other purposes.

 

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Employee and Labor Relations

 

At December 31, 2003, CONSOL Energy had 6,523 employees, 2,767 of whom were represented by the United Mine Workers of America and covered by the terms of the National Bituminous Coal Wage Agreement of 2002 which will expire on December 31, 2006. This agreement was negotiated with the United Mine Workers of America by the Bituminous Coal Operators’ Association on behalf of its members, which include several of CONSOL Energy’s subsidiaries.

 

Regulations

 

The coal mining and gas industries are subject to regulation by federal, state and local authorities on matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of properties after mining or gas operations are completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining and gas operations on groundwater quality and availability. In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for CONSOL Energy’s coal. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on CONSOL Energy’s mining or gas operations or its customers’ ability to use coal or gas and may require CONSOL Energy or its customers to change their operations significantly or incur substantial costs.

 

Numerous governmental permits and approvals are required for mining and gas operations. CONSOL Energy is, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal or gas may have upon the environment and public and employee health and safety. All requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment, health and safety and, as a consequence, the activities of CONSOL Energy may be more closely regulated. Such legislation and regulations, as well as future interpretations of existing laws, may require substantial increases in equipment and operating costs to CONSOL Energy and delays, interruptions or a termination of operations, the extent of which cannot be predicted.

 

While it is not possible to quantify the costs of compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. CONSOL Energy made capital expenditures for environmental control facilities of approximately $1.4 million for the twelve months ended December 31, 2003, $1.4 million for the twelve months ended December 31, 2002, $3.5 million for the six months ended December 31, 2001 and $2.9 million for the twelve months ended June 30, 2001. CONSOL Energy expects to have capital expenditures of $3.7 million for 2004 for environmental control facilities. These costs are in addition to reclamation and mine closing costs. Compliance with these laws has substantially increased the cost of coal mining and gas production, but is, in general, a cost common to all domestic coal and gas producers.

 

Mine Health and Safety Laws

 

Stringent health and safety standards were imposed by federal legislation when the federal Coal Mine Safety and Health Act of 1969 was adopted. The federal Coal Mine Safety and Health Act of 1977, which significantly expanded the enforcement of safety and health standards of the Coal Mine Safety and Health Act of 1969, imposes safety and health standards on all mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations and other matters. The federal Coal Mine Safety and Health Administration monitors compliance with these federal laws and regulations. In addition, as part of the Coal Mine Safety and Health Act of 1969 and the Coal Mine Safety and Health Act of 1977, the Black Lung Benefits Act requires payments of benefits to disabled coal miners with black lung and to certain survivors of miners who die from black lung.

 

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The states in which CONSOL Energy operates have programs for mine safety and health regulation and enforcement. The combination of federal and state safety and health regulations in the coal mining industry is, perhaps, the most comprehensive system for protection of employee safety and health affecting any industry. Most aspects of mine operations, particularly underground mine operations, are subject to extensive regulation. This regulation has a significant effect on CONSOL Energy’s operating costs. However, CONSOL Energy’s competitors in all of the areas in which it operates are subject to the same regulation.

 

Black Lung Legislation

 

Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to:

 

  current and former coal miners totally disabled from black lung disease;

 

  certain survivors of a miner who dies from black lung disease or pneumoconiosis; and

 

  a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner’s last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits.

 

In addition to the federal legislation, we are also liable under various state statutes for black lung claims. Our black lung benefit liabilities, including the current portions, totaled approximately $456 million at December 31, 2003. These obligations are minimally funded at December 31, 2003.

 

In recent years, legislation on black lung reform has been introduced in, but not enacted by, 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.

 

The United States Department of Labor issued a final rule, effective January 19, 2001, amending the regulations implementing the federal black lung laws. The amendments give greater weight to the opinion of the 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 black lung regulations could significantly increase our exposure to black lung benefits liabilities. Experience to date related to these changes is not sufficient to determine the impact of these changes. The National Mining Association, an industry association of which CONSOL Energy is a member, challenged the amendments but the courts, to date, with minor exception, affirmed the rules. However, the decision left many contested issues open for interpretation. Consequently, we anticipate increased litigation until the various federal District Courts have had an opportunity to rule on these issues.

 

Workers’ Compensation

 

CONSOL Energy is required to compensate employees for work-related injuries. Our workers’ compensation liabilities, including the current portion, were $316 million at December 31, 2003. These obligations are unfunded. The amount we expensed in the twelve months ended December 31, 2003, was $53 million, while the related cash payment for this liability was $57 million. Several states in which we operate consider changes in workers’ compensation laws from time to time. Such changes, if enacted, could adversely affect CONSOL Energy.

 

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CONSOL Energy changed its method of accounting for workers’ compensation effective January 1, 2004. Prior to the change, the Company recorded its workers’ compensation liability on an undiscounted basis. Under the new method, the Company will record the liability on a discounted basis, which will be actuarially determined using various assumptions, including discount rate and future cost trends. CONSOL Energy believes this change is preferable since it will align the accounting with the Company’s other long-term employee benefit obligations, which are recorded on a discounted basis. Additionally, it will provide a better comparison with the Company’s 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 be decreased by approximately $132 million and deferred tax assets will be reduced by approximately $51 million as a result of this accounting change.

 

Retiree Health Benefits Legislation

 

The Coal Industry Retiree Health Benefit Act of 1992 requires CONSOL Energy to make payments to fund the cost of health benefits for our and other coal industry retirees. Based on current law and available information, at December 31, 2003, CONSOL Energy’s obligation is estimated at approximately $640 million. We made payments of $38 million ($35 million expensed and $3 million capitalized) for such health benefits in the twelve months ended December 31, 2003.

 

Environmental Laws

 

CONSOL Energy is subject to various federal environmental laws, including

 

  the Surface Mining Control and Reclamation Act of 1977,

 

  the Clean Air Act,

 

  the Clean Water Act,

 

  the Toxic Substances Control Act,

 

  the Comprehensive Environmental Response, Compensation and Liability Act, and

 

  the Resource Conservation and Recovery Act

 

as well as state laws of similar scope in each state in which CONSOL Energy operates.

 

These environmental laws require reporting, permitting and/or approval of many aspects of coal mining and gas operations. Both federal and state inspectors regularly visit mines and other facilities to ensure compliance. CONSOL Energy has ongoing compliance and permitting programs designed to ensure compliance with such environmental laws.

 

Given the retroactive nature of certain environmental laws, CONSOL Energy has incurred and may in the future incur liabilities in connection with properties and facilities currently or previously owned or operated as well as sites to which CONSOL Energy or its subsidiaries sent waste materials.

 

Surface Mining Control and Reclamation Act

 

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. The Act requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of

 

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mining activities. Permits for all mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement or, where state regulatory agencies have adopted federally approved state programs under the Act, the appropriate state regulatory authority. All states in which CONSOL Energy’s active mining operations are located have achieved primary jurisdiction for enforcement of the Act through approved state programs.

 

The Surface Mining Control and Reclamation Act and similar state statutes, among other things, require that mined property be restored in accordance with specified standards and approved reclamation plans. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. The earliest a reclamation bond can be released is five years after reclamation has been achieved. All states impose on mine operators the responsibility for repairing or compensating for damage occurring on the surface as a result of mine subsidence, a possible consequence of longwall mining. In addition, the Abandoned Mine Reclamation Fund, which is part of the Surface Mining Control and Reclamation Act, imposes a tax on all current mining operations, the proceeds of which are used to restore unreclaimed mines closed before 1977. The maximum tax is $.35 per ton on surface-mined coal and $.15 per ton on underground-mined coal.

 

In January 2003, CONSOL Energy adopted Statement of Financial Accounting Standards No. 143 (SFAS 143) to account for the costs related to the closure of mines and gas wells 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. Asset retirement obligations primarily relate to the closure of mines and gas wells and the reclamation of the land upon exhaustion of coal and gas reserves. The effect of this change was 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. The amounts 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.

 

Our reclamation and mine-closing liabilities, including the current portion, were $383 million at December 31, 2003. Our future operating results would be adversely affected if these accruals are determined to be insufficient. These obligations are unfunded. The amount that was expensed for the twelve months ended December 31, 2003 was $16 million, while the related cash payment for such liability during the same period was $33 million.

 

Under the Surface Mining Control and Reclamation Act, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators can be imputed to other companies which are deemed, according to the regulations, to have “owned” or “controlled” the contract mine operator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked from receiving new permits and revocation of any permits that have been issued since the time of the violations or, in the case of civil penalties and reclamation fees, since the time such amounts became due.

 

Clear Air Act

 

The federal Clean Air Act and similar state laws and regulations, which regulate emissions into the air, affect coal mining, gas and processing operations primarily through permitting and/or emissions control requirements. In addition, the United States Environmental Protection Agency has issued certain, and is considering further, regulations relating to fugitive dust and coal combustion emissions which could restrict CONSOL Energy’s ability to develop new mines or require CONSOL Energy to modify its operations. In July 1997, the United States Environmental Protection Agency adopted new, more stringent National Ambient Air Quality Standards for particulate matter which may require some states to change existing implementation plans. Because coal mining operations and plants burning coal emit particulate matter, CONSOL Energy’s mining operations and utility customers are likely to be directly affected when the revisions to the National Ambient Air

 

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Quality Standards are implemented by the states. Regulations may restrict CONSOL Energy’s ability to develop new mines or could require CONSOL Energy to modify its existing operations, and may have a material adverse effect on CONSOL Energy’s financial condition and results of operations.

 

The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal fueled electric power generating plants. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. New environmental regulations governing emissions from coal-fired electric generating plants could reduce demand for coal as a fuel source and affect the volume of our sales. For example, the federal Clean Air Act places limits on sulfur dioxide emissions from electric power plants. In order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users 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 low sulfur coal or other fuels. 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 lower sulfur coal or other low-sulfur fuel could materially affect us if we cannot offset the cost of sulfur removal by lowering the costs of delivery 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 various 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 throughout the eastern United States. The United States Environmental Protection Agency (EPA) 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. EPA is also working on an implementation plan for the 8-hour ozone standard and this may require some customers to further reduce nitrogen oxide emissions, a precursor of ozone. In addition, the EPA has issued draft regulations, and 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 in the planning and building of utility power plants in the future. To the extent that any new and proposed requirements affect our customers, this could adversely affect our operations and results.

 

A regional haze program initiated by the EPA to protect and to improve visibility at and around national parks, national wilderness areas and international parks may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations.

 

The Clean Air Act also imposes standards on sources of hazardous air pollutants. Rules regulating mercury emissions from coal-fired power plants were proposed by the EPA on January 30, 2004. These proposed rules, when finalized, will establish mercury emissions standards for both new and existing coal-fired power plants. Depending on the emission control option used in the final rule, coal-fired power plants will be required to address mercury emissions by 2010, and perhaps earlier. This will likely require significant new investment in controls by many power plant operators. These standards and future standards could have the effect of decreasing demand for coal.

 

The United States Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities and brought an administrative action against one government-owned utility for alleged violations of the Clean Air Act. These lawsuits could require the utilities to pay penalties, install pollution control equipment or undertake other emission reduction measures which could adversely impact their demand for coal.

 

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Any reduction in coal’s share of the capacity for power generation could have a material adverse effect on CONSOL Energy’s business, financial condition and results of operations. The effect such regulations, or other requirements that may be imposed in the future, could have on the coal industry in general and on CONSOL Energy in particular cannot be predicted with certainty.

 

CONSOL Energy believes it has obtained all necessary permits under the Clean Air Act. The expiration dates of these permits range from April 21, 2004 through June 30, 2008. CONSOL Energy monitors permits required by operations regularly and takes appropriate action to extend or obtain permits as needed. Permitting costs with respect to the Clean Air Act were $104,000 for the twelve months ended December 31, 2003, less than $19,000 for the twelve months ended December 31, 2002, the six months ended December 31, 2001, and the twelve months ended June 30, 2001.

 

Framework Convention On Global Climate Change

 

The United States and more than 160 other nations are signatories to the 1992 United Nations Framework Convention on Climate Change which is intended to reduce or offset emissions of greenhouse gases such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a 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. President Bush and the U.S. Senate officially have opposed the Kyoto Protocol and have proposed an alternative to reduce the intensity of United States emissions of greenhouse gases. If the Kyoto Protocol or other comprehensive regulations focusing on greenhouse gas emissions are implemented 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 coalbed methane gas also may affect the use of coal as an energy source.

 

Clean Water Act

 

The federal Clean Water Act and corresponding state laws affect coal mining and gas operations by imposing restrictions on discharges into regulated effluent waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. CONSOL Energy believes it has obtained all permits required under the Clean Water Act and corresponding state laws and is in substantial compliance with such permits. However, new requirements under the Clean Water Act and corresponding state laws may cause CONSOL Energy to incur significant additional costs that could adversely affect its operating results.

 

Comprehensive Environmental Response, Compensation and Liability Act (Superfund)

 

The Comprehensive Environmental Response, Compensation and Liability Act (Superfund) and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. Our current and former coal mining operations incur, and will continue to incur, expenditures associated with the investigation and remediation of facilities and environmental conditions, including underground storage tanks, solid and hazardous waste disposal and other matters under the Comprehensive Environmental Response, Compensation and Liability Act and similar state environmental laws. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.

 

From time to time, we have been the subject of administrative proceedings, litigation and investigations relating to environmental matters. We have been named as a potentially responsible party at Superfund sites in the past. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us. In September 1991, CONSOL Energy was named a potentially responsible party related to the Buckeye Landfill Superfund Site. The estimated total remaining remediation cost for all

 

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potentially responsible parties is approximately $15 million at December 31, 2003. CONSOL Energy’s portion of this claim is approximately 15% to 20%. CONSOL Energy believes it has a liability for the remaining remediation costs of approximately $2.7 million at December 31, 2003. To date, CONSOL Energy has paid $2.3 million for remediation of this waste disposal site and related expenses.

 

The magnitude of the liability and the cost of complying with environmental laws cannot be predicted with certainty due to the lack of specific information available with respect to many sites, the potential for new or changed laws and regulations and for the development of new remediation technologies and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations.

 

Resource Conservation and Recovery Act

 

The federal Resource Conservation and Recovery Act and corresponding state laws and regulations affect coal mining and gas operations by imposing requirements for the treatment, storage and disposal of hazardous wastes. Facilities at which hazardous wastes have been treated, stored or disposed are subject to corrective action orders issued by the EPA which could adversely affect our results and financial condition.

 

Federal Coal Leasing Amendments Act

 

Mining operations on federal lands in the western United States are affected by regulations of the United States Department of the Interior. The Federal Coal Leasing Amendments Act of 1976 amended the Mineral Lands Leasing Act of 1920 which authorized the leasing of federal lands for coal mining. The Federal Coal Leasing Amendments Act increased the royalties payable to the United States Government for federal coal leases and required diligent development and continuous operations of leased reserves within a specified period of time. Regulations adopted by the United States Department of the Interior to implement such legislation could affect coal mining by CONSOL Energy from federal leases for operations developed on such leases. CONSOL Energy’s only operation with Federal mineral leases is Emery Mine. Emery Mine is not currently mining on the Federal mineral leases and incurred no lease expense in the year ended December 31, 2003. Emery Mine’s asset for advance mining royalty related to the Federal leases was $0.5 million at December 31, 2003. These advance royalties will be amortized on a units-of-production method as the tons related to the lease are mined.

 

Federal Regulation of the Sale and Transportation of Gas

 

Various aspects of CONSOL Energy’s gas operations are regulated by agencies of the Federal government. The Federal Energy Regulatory Commission regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the Federal government has regulated the prices at which gas could be sold. While “first sales” by producers of natural gas, and all sales of condensate and natural gas liquids can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead sales in the natural gas industry began with the enactment of the Natural Gas Policy Act in 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

 

Commencing in April 1992, the Federal Energy Regulatory Commission issued Order Nos. 636, 636-A, 636-B, 636-C and 636-D, which require interstate pipelines to provide transportation services separate, or “unbundled,” from the pipelines’ sales of gas. Also, Order No. 636 requires pipeline operators to provide open

 

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access transportation on a nondiscriminatory basis that is equal for all natural gas shippers. Although Order No. 636 does not directly regulate CONSOL Energy’s production activities, the Federal Energy Regulatory Commission has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry.

 

The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the Federal Energy Regulatory Commission continues to review and modify its open access regulations. In particular, the Federal Energy Regulatory Commission has reviewed its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. In February 2000, the Federal Energy Regulatory Commission issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to “fine tune” the open access regulations implemented by Order No. 636 to accommodate subsequent changes in the market. Key provisions of Order No. 637 include:

 

(1)  waiving the price ceiling for short-term capacity release transactions until September 30, 2002 (which was reversed pursuant to an order on remand issued by the Federal Energy Regulatory Commission on October 31, 2002);

 

(2)  permitting value-oriented peak/off-peak rates to better allocate revenue responsibility between short-term and long-term markets;

 

(3)  permitting term-differentiated rates, in order to better allocate risks between shippers and the pipeline;

 

(4)  revising the regulations related to scheduling procedures, capacity, segmentation, imbalance management, and penalties;

 

(5)  retaining the right of first refusal and the five year matching cap for long-term shippers at maximum rates, but significantly narrowing the right of first refusal for customers that the Federal Energy Regulatory Commission does not deem to be captive; and

 

(6)  adopting new web site reporting requirements that include daily transactional data on all firm and interruptible contracts and daily reporting of scheduled quantities at points or segments.

 

The new reporting requirements became effective September 1, 2000. CONSOL Energy cannot predict what action the Federal Energy Regulatory Commission will take on these matters, nor can it accurately predict whether the Federal Energy Regulatory Commission’s actions will, over the long-term, achieve the goal of increasing competition in markets in which CONSOL Energy’s gas is sold.

 

The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. CONSOL Energy’s gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although CONSOL Energy does not believe that it would be affected by such regulation any differently than other natural gas producers or gatherers. In addition, the Federal Energy Regulatory Commission’s approval of transfers of previously-regulated gathering systems to independent

 

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or pipeline affiliated gathering companies that are not subject to Federal Energy Regulatory Commission regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future.

 

CONSOL Energy owns certain natural gas pipeline facilities that it believes meet the traditional tests which the Federal Energy Regulatory Commission has used to establish a pipeline’s status as a gatherer not subject to the Federal Energy Regulatory Commission jurisdiction. Whether on state or federal land, natural gas gathering may receive greater regulatory scrutiny in the post-Order No. 636 environment.

 

Additional proposals and proceedings that might affect the gas industry are pending before Congress, the Federal Energy Regulatory Commission, the Minerals Management Service, state commissions and the courts. CONSOL Energy cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, CONSOL Energy does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of CONSOL Energy or its subsidiaries. No material portion of CONSOL Energy’s business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the Federal government.

 

State Regulation of Gas Operations—United States

 

CONSOL Energy’s operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. CONSOL Energy’s operations are also subject to various conservation laws and regulations. These include regulations that affect the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of gas properties. In addition, state conservation laws establish maximum rates of production from gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. These regulatory burdens may affect profitability, and CONSOL Energy is unable to predict the future cost or impact of complying with such regulations.

 

Available Information

 

CONSOL Energy maintains a website on the World Wide Web at www.consolenergy.com. CONSOL Energy makes available, free of charge, on its website its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “1934 Act”), as soon as reasonably practicable after such reports are electronically filed with, or furnished to the SEC, and are also available at the SEC’s website at www.sec.gov.

 

Item 2.    Properties.

 

See “Coal Operations” and “Gas Operations” in Item 1 of this 10-K for a description of CONSOL Energy’s properties.

 

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Item 3.    Legal Proceedings.

 

CONSOL Energy is subject to various lawsuits and claims with respect to matters such as personal injury, wrongful death, damage to property, exposure to hazardous substances, environmental remediation, employment and contract disputes, and other claims and actions arising out of the normal course of business.

 

One of CONSOL Energy’s subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is defending against approximately 22,600 asbestos claims in state courts in Pennsylvania, Ohio, West 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 from manufacturers of identified products in certain jurisdictions, 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, there cannot be any assurance that payments in the future with respect to pending or future asbestos cases will not be material to the financial position, results of operations or cash flows of CONSOL Energy.

 

In September 1991, CONSOL Energy was named a potentially responsible party related to the Buckeye Landfill Superfund Site. The estimated total remaining remediation cost for all potentially responsible parties is approximately $15 million at December 31, 2003. CONSOL Energy’s portion of this claim is approximately 15% to 20%. CONSOL Energy believes it has a liability for the remaining remediation costs of approximately $2.7 million at December 31, 2003. To date, CONSOL Energy has paid $2.3 million for remediation of this waste disposal site and related expenses.

 

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 CONSOL Energy, 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) CONSOL Energy utilized an aggressive approach regarding its spot market sales by reserving 20% of its production to that market, and that by increasing its exposure to the spot market, CONSOL Energy was subjecting itself to increased risk and uncertainty as the price and demand for coal could be volatile; (b) CONSOL Energy was experiencing difficulty selling the production that it had allocated to the spot market, and, nonetheless, CONSOL Energy maintained its production levels which caused its inventory to increase; (c) CONSOL Energy’s increasing coal inventory was causing its expenses to rise dramatically, thereby weakening the company’s financial condition; and (d) based on the foregoing, defendants’ positive statements regarding CONSOL Energy’s 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 CONSOL Energy and certain officers and directors. CONSOL Energy has not yet been served with either purported complaint.

 

In the opinion of management, the ultimate liabilities resulting from pending lawsuits and claims will not materially affect its financial position, results of operations or cash flows.

 

Item 4.    Submission of Matters to a Vote of Security Holders.

 

None.

 

36


PART II

 

Item 5.     Market for Registrant’s Common Equity and Related Stockholder Matters.

 

Common Stock Market Prices and Dividends

 

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.

 

See Part III, Item II. Executive Compensation for information relating to CONSOL Energy’s equity compensation plans.

 

37


EXECUTIVE OFFICERS OF CONSOL ENERGY

 

The following is a list of CONSOL Energy’s executive officers, their ages as of February 1, 2004 and their positions and offices held with CONSOL Energy.

 

Name


   Age

  

Position


J. Brett Harvey

   53    President and Chief Executive Officer and Director

Peter B. Lilly

   55    Chief Operating Officer—Coal

Ronald E. Smith

   55    Executive Vice President—Gas Operations, Land Resources and Engineering Services

William J. Lyons

   55    Senior Vice President and Chief Financial Officer

Stephen E. Williams

   55    Vice President—General Counsel and Secretary

Ronald G. Stovash

   55    Senior Vice President—Central Appalachia Operations and Marketing

 

J. Brett Harvey has been President and Chief Executive Officer and a Director of CONSOL Energy since January 1998. Prior to joining CONSOL Energy, Mr. Harvey served as the President and Chief Executive Officer of PacifiCorp Energy Inc., a subsidiary of PacifiCorp, from March 1995 until January 1998. Mr. Harvey also was President and Chief Executive Officer of Interwest Mining Company from January 1993 until January 1998 and Vice President of PacifiCorp Fuels from November 1994 until January 1998.

 

Peter B. Lilly has been Chief Operating Officer-Coal of CONSOL Energy since October 2002. Prior to joining CONSOL Energy, Mr. Lilly served as President and Chief Executive Officer of Triton Coal Company LLC and Vulcan Coal Holdings LLC from 1998 to 2002. Between 1991 and 1998, he served in various positions with Peabody Holding Company, Inc.—President and Chief Operating Officer from 1995 to 1998, Executive Vice President from 1994 to 1995, and as president of Eastern Associated Coal Corporation from 1991 to 1994.

 

Ronald E. Smith has been Executive Vice President—Gas Operations, Land Resources and Engineering Services of CONSOL Energy since April 1, 1992.

 

William J. Lyons has been Senior Vice President and Chief Financial Officer of CONSOL Energy since February 1, 2001. From January 1, 1995 to February 1, 2001, Mr. Lyons held the position of Vice President—Controller for CONSOL Energy.

 

Ronald G. Stovash has been Senior Vice President of Central Appalachia Operations and Marketing for CONSOL Energy since July 2003. From April 2003 to July 2003, Mr. Stovash held the position of Vice President—Sales and Marketing. From October 1999 to April 2003, Mr. Stovash held the position of Vice President—Marketing. Prior to October 1999 Mr. Stovash was Vice President—Morgantown Operations.

 

Stephen E. Williams has been Vice President, General Counsel and Secretary of CONSOL Energy since March 2003. Prior to joining CONSOL Energy, Mr. Williams was a partner in, and Of Counsel to, McGuireWoods LLP. Previously, he was a partner in that firm and the head of its energy and utilities section. From 1993 until 2000, Mr. Williams served as Senior Vice President and General Counsel of Consolidated Natural Gas Company, and held various positions with subsidiaries of that company commencing in 1974.

 

38


Item 6. 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 started January 1, 2002.

 

STATEMENT OF INCOME DATA

(In thousands except per share data)

     Twelve Months Ended December 31,

    Six Months Ended
December 31,


  

Twelve Months

Ended June 30,


   

Six
Months
Ended
June 30,

1999


     2003

    2002

    2001

    2001

    2000

   2001

    2000

   
                 (Unaudited)           (Unaudited)                 

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
    


 


 


 


 

  


 


 

 

39


STATEMENT OF INCOME DATA

(In thousands except per share data)

   Twelve Months Ended December 31,

   Six Months Ended
December 31,


  

Twelve Months

Ended June 30,


  

Six Months
Ended
June 30,

1999


     2003

   2002

   2001

   2001

   2000

   2001

   2000

  
               (Unaudited)         (Unaudited)               

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
    

  

  

  

  

  

  

  

 

BALANCE SHEET DATA

(In thousands)

   At December 31,

   
    At June 30,

 
     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  

 

40


OTHER OPERATING DATA

(Unaudited)

    

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  

CASH FLOW STATEMENT DATA

(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

 
                 (Unaudited)           (Unaudited)                     

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.

 

41


(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 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 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:

 

   

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

 
                (Unaudited)           (Unaudited)                    

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  
   


 


 


 


 


 


 


 



(I) 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.

 

Item 7. 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.

 

42


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 company 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 company 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 the company 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 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

 

43


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 the company 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 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.

 

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.

 

44


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 Principle

     (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 the Company’s 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.

 

45


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 Company 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 company 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 company 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 Company 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

 

46


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.

 

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

 

47


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 company 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 included in this Form 10-K for the year ended December 31, 2003. Cost per ton for produced coal also increased due to higher supply cost per unit. These increases in costs were offset, in part, by reduced company 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  %

 

48


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 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 %
    

  

  

      

 

49


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, Eighty-Four Mine 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 )%

 

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

 

50


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 Form 10-K for the year ended December 31, 2003.

 

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 the company.

 

Other selling, general and administrative costs increased primarily due to 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.

 

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.

 

51


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