Form 10-K
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2004;

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:

 

Title of each class


 

Name of exchange on which registered


Common Stock ($.01 par value)   New York Stock Exchange

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 (Section 229-405 of this chapter) 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 Rule 12b-2 of the Act)    Yes  x     No  ¨

The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 2004, 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 $3,247,692,804.

The number of shares outstanding of the registrant’s common stock as of February 17, 2005 is 91,114,365 shares.

 

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of Consol Energy’s Proxy Statement for the Annual Meeting of Shareholders to be held on May 3, 2005,

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

 



Table of Contents

TABLE OF CONTENTS

 

          Page

PART I

    

Item 1.

   Business    4

Item 2.

   Properties    32

Item 3.

   Legal Proceedings    33

Item 4.

   Submission of Matters to a Vote of Security Holders    34
     Executive Officers of CONSOL Energy    34

PART II

    

Item 5.

   Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities    35

Item 6.

   Selected Financial Data    36

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations    41

Item 7A.

   Quantitative and Qualitative Disclosures About Market Risk    81

Item 8.

   Financial Statements and Supplementary Data    83

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosures    145

Item 9A.

   Controls and Procedures    145

Item 9B.

   Other Information    145

PART III

    

Item 10.

   Directors and Executive Officers of the Registrant    146

Item 11.

   Executive Compensation    146

Item 12.

   Security Ownership of Certain Beneficial Owners and Management    146

Item 13.

   Certain Relationships and Related Transactions    146

Item 14.

   Principal Accounting Fees and Services    146

PART IV

    

Item 15.

   Exhibits and Financial Statement Schedules    147

SIGNATURES

   152

 

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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:

 

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

 

    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;

 

    our inability to hire qualified people to meet replacement or expansion needs;

 

    uncertainties in estimating our economically recoverable coal and gas reserves;

 

    risks in exploring for and producing gas;

 

    obtaining governmental permits and approvals for our operations;

 

    a loss of our competitive position because of the competitive nature of the coal industry and the gas industry, or a loss of our competitive position because of overcapacity in these industries impairing our profitability;

 

    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;

 

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

 

    reliance on major customers;

 

    our inability to collect payments from customers if their creditworthiness declines;

 

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

 

    the effects of government regulation;

 

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

 

    the incurrence of losses in future periods;

 

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

 

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

 

    increased exposure to employee related long-term liabilities;

 

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

 

    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 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;

 

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

 

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

 

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Table of Contents
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, 2004, we produce high-Btu bituminous coal from 17 mining complexes in the United States. 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 68 million tons of coal in 2004 accounted for approximately 6% of the total tons produced in the United States and approximately 14% of the total tons produced east of the Mississippi River during 2004. 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 east of the Mississippi River;

 

    We are one of the largest exporters of coal from the United States;

 

    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 position as a gas producer is highlighted by several measures:

 

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

 

    We currently have approximately 156 million cubic feet of gross average daily production;

 

    At December 31, 2004, we operated more than 1,825 wells connected by approximately 885 miles of gathering lines and associated infrastructure; and

 

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

 

    We controlled 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 at December 31, 2004.

 

Additionally, we provide energy services, including terminal services, industrial supply services and coal waste disposal services.

 

CONSOL Energy was organized as a Delaware corporation in 1991.

 

Recent Events

 

CONSOL Energy’s Buchanan Mine, located near Keen Mountain, Virginia, experienced a large rock fall behind its longwall mining section on February 14, 2005. While caving behind the longwall is a normal part of the mining process, the size of this cave-in created a large air pressure wave that disrupted ventilation and also

 

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caused an ignition of methane gas in the area. CONSOL Energy has temporarily sealed the mine in order to extinguish the localized fire that developed after the ignition. Based on a review of gas samples from the mine that have been collected and analyzed by CONSOL Energy as well as by state and federal safety officials, it has been determined that the fire exists in a localized area adjacent to the longwall mining system. In addition to sealing the mine, CONSOL Energy plans to drill several boreholes from the surface into the area of the mine where the problem is believed to be located. An initial borehole drilling has penetrated the mine at the place where a mine fire was suspected to have started. Video equipment lowered into the borehole to visually inspect the area shows that the location is clear of any fire or smoke. Various materials, including nitrogen foam and water will be pumped into the area in order to accelerate the process of creating an inert environment within the mine to extinguish the fire. The mine is currently idle and will not produce coal while the mine is sealed. Gas production from this area may also be curtailed due to the idling of the Buchanan longwall. Gas production from this area averaged 23.6 thousand cubic feet per day in January 2005.

 

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 of metallurgical coal, sold to metal and coke producers. The Coal unit includes four reportable segments. These reportable segments are Northern Appalachia, Central Appalachia, Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines). For the year ended December 31, 2004, the Northern Appalachia aggregated segment includes the following mines: Shoemaker, Blacksville #2, Robinson Run, McElroy, Bailey, Loveridge, Enlow Fork and Mine 84. For the year ended December 31, 2004, the Central Appalachia aggregated segment includes the following mines: Jones Fork, Mill Creek and Wiley-Mill Creek. For the year ended December 31, 2004, the Metallurgical aggregated segment includes the following mines: Buchanan, Amonate, Miles Branch and V.P. #8. The Other Coal segment includes CONSOL Energy’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 coalbed methane gas for sale primarily to gas wholesalers. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the twelve months ended December 31, 2004, 2003 and 2002 is included in Note 29 of Notes to Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.

 

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Coal Operations

 

Mining Complexes

 

At December 31, 2004, CONSOL Energy had 17 mining complexes located in the United States.

 

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

 

LOGO

 

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Table of Contents

The following table provides the location of each of CONSOL Energy’s mining complexes at December 31, 2004 and 2003, 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. In February 2004, we sold our interest in the Glennies Creek Mine.

 

CONSOL ENERGY MINING COMPLEXES

Average Quality and Recoverable Reserves as of December 31, 2004

 

Mine/Reserve


  Location

  Reserve Class

  Coal Seam

 

Average

Seam
Thickness

(feet)


 

Average Coal Quality

(As-Received)(1)


 

Recoverable Reserves

(12/31/04)(2)


 

Recoverable

Reserves

(tons in
Millions)

12/31/2003


         

Moisture

(%)


 

Sulfur

(%)


  Heat Value
(Btu/lb)


  Owned
(%)


    Leased
(%)


    Tons (in
Millions)


 

ASSIGNED—OPERATING

                                               

Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)

                                               

Enlow Fork

  Enon, PA   Assigned   Pittsburgh   5.05   6.0   1.68   13,286   78 %   22 %   50.9   58.3
        Accessible   Pittsburgh   5.40   6.0   1.92   13,219   82 %   18 %   164.9   165.5

Bailey

  Enon, PA   Assigned   Pittsburgh   5.64   6.0   2.00   13,223   12 %   88 %   86.0   96.1
        Accessible   Pittsburgh   5.75   6.0   2.47   13,176   49 %   51 %   142.6   142.6

Mine 84

  Eighty Four, PA   Assigned   Pittsburgh   5.61   6.0   1.49   13,394   58 %   42 %   45.4   49.3
        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 %   —   %   166.2   174.5

Shoemaker

  Moundsville, WV   Assigned   Pittsburgh   5.54   7.3   3.40   12,864   99 %   1 %   42.2   45.2
        Accessible   Pittsburgh   5.55   7.3   2.96   12,930   100 %   —   %   5.2   5.2

Loveridge

  Fairview, WV   Assigned   Pittsburgh   7.82   6.0   2.48   13,236   100 %   —   %   8.2   13.0
        Accessible   Pittsburgh   7.59   6.0   2.90   13,187   93 %   7 %   93.8   93.9

Robinson Run

  Shinnston, WV   Assigned   Pittsburgh   7.40   6.0   3.33   13,154   77 %   23 %   27.3   28.4
        Accessible   Pittsburgh   6.92   6.0   3.52   13,157   75 %   25 %   206.2   113.6

Blacksville 2

  Wana, WV   Assigned   Pittsburgh   6.62   6.0   2.88   12,838   100 %   —   %   21.2   34.5
        Accessible   Pittsburgh   6.77   6.0   2.71   13,239   98 %   2 %   55.7   60.8

Mahoning Valley

  Cadiz, OH   Assigned   Multiple   4.34   6.7   2.08   11,517   100 %   —   %   4.5   5.2

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

                                               

Buchanan

  Mavisdale, VA   Assigned   Pocahontas 3   5.66   6.3   0.68   14,057   11 %   89 %   56.6   43.8
        Accessible   Pocahontas 3   6.07   6.3   0.65   14,011   12 %   88 %   64.4   81.6

VP-3

  Vansant, VA   Assigned   Pocahontas 3   —     —     —     —     —   %   —   %   —     7.8

VP-8

  Rowe, VA   Assigned   Pocahontas 3   5.24   9.0   0.77   13,581   4 %   96 %   0.9   2.4

Mill Creek Complex

  Deane, KY   Assigned   Multiple   3.76   6.4   1.55   13,324   94 %   6 %   16.8   20.2
        Accessible   Multiple   4.42   5.5   1.18   12,261   100 %   —   %   0.7   0.7

Jones Fork Complex

  Mousie, KY   Assigned   Multiple   3.64   7.0   1.03   13,132   37 %   63 %   33.3   34.5
        Accessible   Multiple   3.48   7.2   0.97   12,922   61 %   39 %   4.9   4.9

Amonate Complex

  Amonate, VA   Assigned   Multiple   3.51   6.8   0.72   13,122   28 %   72 %   9.3   7.3

Miles Branch

  Bishop, VA   Assigned   Pocahontas 5   3.60   6.8   0.51   12,977   100 %   —   %   1.8   2.1

Miller Creek

  Mingo County, WV   Assigned   Multiple   8.53   7.2   0.70   12,443   —   %   100 %   6.8   —  

Illinois Basin (Illinois, Western Kentucky)

                                               

Rend Lake

  Sesser, IL   Assigned   Illinois 6   —     —     —     —     —   %   —   %   —     21.3
        Accessible   Illinois 6   —     —     —     —     —   %   —   %   —     33.7

Ohio 11

  Morganfield, KY   Assigned   Kentucky 11   —     —     —     —     —   %   —   %   —     8.3
        Accessible   Kentucky 11   —     —     —     —     —   %   —   %   —     2.2

Western U.S. (Utah)

                                               

Emery

  Emery Co., UT   Assigned   Ferron I   7.50   7.0   0.73   11,803   80 %   20 %   21.2   21.5
        Accessible   Ferron A   8.82   7.0   0.93   11,683   47 %   53 %   12.3   12.3

Assets Sold in February, 2004

                                               

Australia (New South Wales)

                                               

Glennies Creek

  Hunter Valley, NSW   Assigned   Middle Liddel   —     —     —     —     —   %   —   %   —     9.6

Total Assigned Operating and Accessible

                                          1,407.8   1,458.8

 

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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.

 

Excluded from the table above are approximately 126.7 million tons of reserves at December 31, 2004 that are assigned to projects that have not produced coal in 2004 or 2003. These assigned reserves are in the Northern Appalachia (Pennsylvania, Ohio and northern West Virginia), Central Appalachia (Virginia, southern West Virginia and eastern Kentucky) and Illinois Basin (Illinois and western Kentucky) regions. These reserves are approximately 55% owned and 45% leased. Average quality on an “as-received” basis ranges from 5.7% to 11.8% moisture content, 0.54% to 4.05% sulfur content and 11,877 to 14,097 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 are 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 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.

 

Coal Reserves

 

At December 31, 2004, CONSOL Energy had an estimated 4.5 billion tons of proven and probable reserves. Reserves are the portion of the proven and probable tonnage that meet CONSOL Energy’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels.

 

Proven reserves are reserves for which:

 

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

 

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(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 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 seam for which points of observation are between 3,000 feet and 8,000 feet 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 seam for which points of observation are between 3,000 and 8,000 feet 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, such as, sulfur content, ash and heating value. Modern power plant boiler design aspects can compensate for coal quality differences that occur. Therefore, any of CONSOL Energy’s coals can be marketed for power generation.

 

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

 

CONSOL Energy’s reserves are located in northern Appalachia (58%), central Appalachia (10%), the mid-western United States (20%), the western United States (10%), and in western Canada (2%) at December 31, 2004.

 

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

 

CONSOL Energy—UNASSIGNED Recoverable Coal Reserves as of 12/31/04

   

Range of Average Product

Quality

(As-Received)(1)


 

Recoverable Reserves

12/31/04(2)


 

Recoverable
Reserves
(tons in

Millions)

12/31/2003


Coal Producing Region


  Moisture
(%)


  Sulfur
(%)


  Heat Value
(Btu/lb)


 

Owned

(%)


   

Leased

(%)


    Tons
(in millions)


 

Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)

  4.5-8.5   0.69-3.75   10,362-13,514   77 %   23 %   1,360.7   1,032.7

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

  6.0-7.2   0.51-1.26   12,186-14,215   48 %   52 %   194.6   167.3

Illinois Basin (Illinois, Western Kentucky, Indiana)

  11.3-12.0   0.77-2.89   11,481-12,106   35 %   65 %   850.8   817.7

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   129.1

Total

              57 %   43 %   2,974.6   2,586.2

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, 2004 by region and type of coal or sulfur content (sulfur content per million British thermal unit). Proven and probable reserves include both assigned and unassigned reserves. Amounts for unassigned reserves are net amounts based on various recovery rates reflecting CONSOL Energy’s experience in recovering coal from seams. In reporting unassigned reserves, CONSOL Energy has assumed approximately 60% recovery of in-place coal for reserves that can be mined using the longwall method, approximately 50% recovery of in-place coal for reserves that will be mined using other underground methods and approximately 90% recovery for surface mines.

 

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

 

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Table of Contents

CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES

BY PRODUCING REGION AND PRODUCT (IN MILLIONS OF TONS) AS OF DECEMBER 31, 2004

 

     £1.20 lbs

    > 1.20 £ 2.50 lbs

    > 2.50 lbs

             
     S02/MMBtu

    S02/MMBtu

    S02/MMBtu

             

By Region


   Low
Btu


    Med
Btu


    High
Btu


    Low
Btu


    Med
Btu


    High
Btu


    Low
Btu


    Med
Btu


    High
Btu


    Total

    Percentage
By Region


 

Northern Appalachia:

                                                                  

Metallurgical:

                                                                  

High Vol A Bituminous

   —       —       —       —       —       187.2     —       —       —       187.2     4.2 %

Steam:

                                                                  

High Vol A Bituminous

   —       49.4     —       —       10.0     45.4     37.8     47.5     2,205.3     2,395.4     53.1 %

Low Vol Bituminous

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

 

 

 

 

 

 

 

 

 

 

Region Total

   —       49.4     —       —       10.0     248.5     37.8     47.5     2,205.3     2,598.5     57.7 %

Central Appalachia:

                                                                  

Metallurgical:

                                                                  

High Vol A Bituminous

   —       7.3     18.4     —       —       2.1     —       —       —       27.8     0.6 %

Med Vol Bituminous

   1.0     1.8     70.1     —       —       —       —       —       —       72.9     1.6 %

Low Vol Bituminous

   —       —       141.1     2.3     —       —       —       —       —       143.4     3.3 %

Steam:

                                                                  

High Vol A Bituminous

   25.3     19.0     9.2     33.1     3.9     82.7     —       —       11.2     184.4     4.1 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   26.3     28.1     238.8     35.4     3.9     84.8     —       —       11.2     428.5     9.6 %

Midwest – Illinois Basin:

                                                                  

Steam:

                                                                  

High Vol B Bituminous

   —       —       —       —       66.0     55.0     36.6     437.1     35.5     630.2     14.0 %

High Vol C Bituminous

   —       —       —       —       158.1     —       92.0     —       —       250.1     5.5 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   —       —       —       —       224.1     55.0     128.6     437.1     35.5     880.3     19.5 %

Northern Powder River Basin:

                                                                  

Steam:

                                                                  

Subbituminous B

   —       —       252.7     —       —       —       —       —       —       252.7     5.6 %

Subbituminous C

   —       186.6     —       —       —       —       —       —       —       186.6     4.1 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   —       186.6     252.7     —       —       —       —       —       —       439.3     9.7 %

Utah – Emery Field:

                                                                  

High Vol B Bituminous

   —       —       —       —       33.5     —       —       —       —       33.5     0.7 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   —       —       —       —       33.5     —       —       —       —       33.5     0.7 %

Western Canada:

                                                                  

Metallurgical:

                                                                  

Med Vol Bituminous

   18.6     86.1     —       —       —       —       —       —       —       104.7     2.3 %

Low Vol Bituminous

   22.5     1.8     —       —       —       —       —       —       —       24.3     0.5 %
    

 

 

 

 

 

 

 

 

 

 

Region Total

   41.1     87.9     —       —       —       —       —       —       —       129.0     2.8 %
    

 

 

 

 

 

 

 

 

 

 

Total Company

   67.4     352.0     491.5     35.4     271.5     388.3     166.4     484.6     2,252.0     4,509.1     100.0 %
    

 

 

 

 

 

 

 

 

 

 

Percent of Total

   1.5 %   7.8 %   10.9 %   0.8 %   6.0 %   8.6 %   3.7 %   10.8 %   49.9 %   100.0 %      
    

 

 

 

 

 

 

 

 

 

     

 

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CONSOL ENERGY PROVEN AND PROBABLE COAL RECOVERABLE RESERVES BY PRODUCT

(MILLIONS OF TONS) AS OF DECEMBER 31, 2004

 

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

   —       7.3     18.4     —       —       189.3     —       —       —       215.0     4.8 %

Med Vol Bituminous

   19.6     87.9     70.1     —       —       —       —       —       —       177.6     3.9 %

Low Vol Bituminous

   22.5     1.8     141.1     2.3     —       —       —       —       —       167.7     3.7 %
    

 

 

 

 

 

 

 

 

 

 

Total Metallurgical

   42.1     97.0     229.6     2.3     —       189.3     —       —       —       560.3     12.4 %

Steam:

                                                                  

High Vol A Bituminous

   25.3     68.4     9.2     33.1     13.9     128.1     37.8     47.5     2,216.5     2,579.8     57.3 %

High Vol B Bituminous

   —       —       —       —       99.5     55.0     36.6     437.1     35.5     663.7     14.7 %

High Vol C Bituminous

   —       —       —       —       158.1     —       92.0     —       —       250.1     5.5 %

Low Vol Bituminous

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

Subbituminous B

   —       —       252.7     —       —       —       —       —       —       252.7     5.6 %

Subbituminous C

   —       186.6     —       —       —       —       —       —       —       186.6     4.1 %
    

 

 

 

 

 

 

 

 

 

 

Total Steam

   25.3     255.0     261.9     33.1     271.5     199.0     166.4     484.6     2,252.0     3,948.8     87.6 %
    

 

 

 

 

 

 

 

 

 

 

Total

   67.4     352.0     491.5     35.4     271.5     388.3     166.4     484.6     2,252.0     4,509.1     100.0 %
    

 

 

 

 

 

 

 

 

 

 

Percent of Total

   1.5 %   7.8 %   10.9 %   0.8 %   6.0 %   8.6 %   3.7 %   10.8 %   49.9 %   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 and Canada

   < 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.

 

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Table of Contents

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, 2004, 0.9 billion tons, or 20%, 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 standards for power plants, the Environmental Protection Agency is expected to promulgate a new regulatory program for controlling mercury early in 2005. 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, 2004, 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, 2004, 87% 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.

 

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Table of Contents

The following table shows the production, in millions of tons, for CONSOL Energy’s mines in the twelve months ended December 31, 2004, 2003 and 2002, 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 four mines, Dilworth, Humphrey, Meigs, 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. In February 2004, we sold our interests in Glennies Creek Mine in Australia. 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


          2004

  2003

  2002

 

Northern Appalachia

                               

Enlow Fork

  Enon, Pennsylvania   U   LW/CM   R R/B   10.2   9.9   9.6   1990

Bailey

  Enon, Pennsylvania   U   LW/CM   R R/B   10.1   9.4   9.7   1984

McElroy

  Glen Easton, West Virginia   U   LW/CM   B   8.2   6.3   4.7   1968

Robinson Run

  Shinnston, West Virginia   U   LW/CM   R CB   6.3   5.7   5.0   1966

Mine No. 84

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

Blacksville 2

  Wana, West Virginia   U   LW/CM   R R/B T   5.7   5.4   4.8   1970

Dilworth(1)

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

Shoemaker

  Moundsville, West Virginia   U   LW/CM   B   3.7   3.8   3.4   1966

Loveridge(2)

  Fairview, West Virginia   U   LW/CM   R T   4.8   —     —     1956

Humphrey(1)

  Maidsville, West Virginia   U   CM   R   —     —     0.5   1956

Mahoning Valley

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

Meigs(1)

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

Windsor(1)

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

Central Appalachia

                               

Buchanan

  Mavisdale, Virginia   U   LW/CM   R   4.4   4.7   4.1   1983

VP-8

  Rowe, Virginia   U   LW/CM   R   1.5   1.9   2.2   1993

Mill Creek(3)

  Deane, Kentucky   U/S   CM   R   3.8   3.7   3.5   1994

Jones Fork(3)

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

Amonate(3)

  Amonate, Virginia   U   CM   R   0.4   0.6   0.5   1925

Miles Branch

  Bishop, Virginia   U   CM   T R   0.3   0.1   —     2003

Miller Creek(3)

  Mingo County, West Virginia   U/S   CM/S/L   T   0.3   —     —     2004

Illinois Basin

                               

Rend Lake(4)

  Sesser, Illinois   U   CM   R T   —     —     1.7   1986

Western U.S.

                               

Emery(4)

  Emery County, Utah   U   LW/CM   T   0.3   0.2   —     1945

Western Canada

                               

Cardinal River(5)

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

Line Creek(5)

  Sparwood, British Columbia, Canada   S   S/L   R   —     0.2   1.7   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, Miller 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, 2004, 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.

 

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Table of Contents

The amounts shown for tons produced for all periods presented by Cardinal River, Line Creek and Glennies Creek 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:

 

     Years Ended December 31,

     2004

   2003

   2002

Average Sales Price for Ton Produced

   $ 30.06    $ 27.61    $ 26.76

 

In 2004, several facets of planned expansion projects were completed at our mining complexes. The majority of the McElroy Mine expansion project has been completed. Both coal preparation plants, the second longwall, the 7,500-ton underground coal storage bunker, the refuse belt system and the harbor upgrade are now operational. This contributed to record annual production at McElroy in 2004. In addition, a 200,000-ton capacity clean coal storage area is being constructed at McElroy which we anticipate will be operational by mid-2005. The Bailey Preparation Plant expansion, a mine coal processing facility shared by the Bailey and Enlow Fork mines, also was completed in 2004. As a result, production capacity has been increased at these two operations. Work continues on expansion of a new coal refuse area and overland refuse conveyor which we anticipate a first quarter 2005 completion date.

 

During the second quarter of 2004, two converging geologic features were encountered by the Mine 84 longwall severely impacting production. These mining difficulties, coupled with advanced geologic exploration, resulted in the redesign of the mining plan and changes in usage plans for equipment. As a result of these changes in the mine plan and utilization of the newly constructed Hallam mine portal, longwall productivity for September 2004 through December 2004 improved compared to the January 2004 through August 2004 period. Work continues on improving longwall panel development timing. Existing geologic information has been incorporated in our mine exploration program and our mining plans at Mine 84 to avoid future geologic anomalies.

 

The Loveridge Mine resumed full production at the end of the first quarter of 2004, ahead of the original 2003 post-fire schedule. This, along with improvements to plant yield and mine productivity, contributed to strong safety and production results in 2004.

 

Mining was completed in the area supported by the Bailey main west beltline. The system was de-commissioned in June 2004 and materials that could be used elsewhere were recovered. The clearing of this area of the mine reduced haulage distances and enhance productivity. Both Bailey longwalls were brought into full production in October 2004, after a planned outage to repair structural conditions identified in 2003 on the longwall face shields. During this outage the complete set of longwall face shields was removed from the mine, repaired and returned to the mine.

 

The Emery Mine in central Utah was reactivated in the third quarter of 2004. The underground operation began supplying a low-sulfur, 12,000 British thermal unit per pound of coal to new western industrial and utility customers.

 

In October 2004, the Miller Creek surface and underground mining complex was activated to supplement Central Applachian production. Initial mining consists of mountaintop surface coal removal and a deep mine in southern West Virginia. Contractors operate both surface and underground mines.

 

Title to coal properties that we lease or purchase and the boundaries of these 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 reserves could be adversely affected.

 

15


Table of Contents

The following table sets forth, with respect to properties that we lease to other coal operators, the total royalty tonnage, 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, 2004, 2003 and 2002.

 

Year


  

Total Royalty
Tonnage

(in thousands)


  

Total
Coal

Acreage
Leased


  

Total Royalty
Income

(in thousands)


2004

   18,249    242,160    $ 6,001

2003

   17,633    244,109    $ 6,266

2002

   17,680    202,033    $ 7,451

 

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.

 

At December 31, 2004, CONSOL Energy operates approximately 24% 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 2004.

 

MAJOR U.S. UNDERGROUND COAL MINES—2004

In millions of tons

 

Mine Name


  

Operating Company


   Production

Enlow Fork

  

CONSOL Energy

   10.2

Bailey

  

CONSOL Energy

   10.1

Foidel Creek Mine

  

Twentymile Coal Company

   8.6

McElroy

  

CONSOL Energy

   8.4

San Juan

  

San Juan Coal Company

   7.7

SUFCO

  

Canyon Fuel Company

   7.6

Elk Creek

  

Oxbow Mining, LLC

   6.5

Galatia

  

The American Coal Co.

   6.5

West Elk

  

Mountain Coal Company

   6.5

Robinson Run

  

CONSOL Energy

   6.2

Century

  

American Energy Corp.

   5.8

Emerald

  

Emerald Coal Resources, LP.

   5.8

Blacksville 2

  

CONSOL Energy

   5.7

Cumberland

  

Cumberland Coal Resources, LP.

   5.2

Loveridge

  

CONSOL Energy

   5.0

Federal No. 2

  

Eastern Associated Coal Corp.

   4.9

Dotiki

  

Webster County Coal LLC

   4.8

Buchanan

  

CONSOL Energy

   4.4

Powhatan No. 6

  

The Ohio Valley Coal Company

   4.3

American Eagle Mine

  

Speed Mining, LLC

   4.1

Source: National Mining Association

 

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 2004, we sold 70 million tons of coal, including our percentage of sales in equity affiliates, 91% of which was sold in domestic markets. Our direct sales to domestic electricity generators represented 68% of our total tons

 

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sold in 2004. Including equity affiliate sales, we had approximately 155 customers in 2004. During 2004, Allegheny Energy accounted for 11% of our total revenue. No other customers accounted for more than 10% of total revenue in 2004.

 

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, 2004, 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 a combination of the above features, 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 transactions and published information 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 January 12, 2005, the total tons of coal CONSOL Energy is committed to deliver from 2005 through 2009.

 

    

Tons of Coal to be Delivered

(in millions of nominal tons)


     2005

   2006

   2007

   2008

   2009

(1) Commitments to deliver coal at predetermined prices

   65.1    46.7    25.4    11.3    3.3

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

   2.5    6.2    7.9    10.4    11.2
    
  
  
  
  
     67.6    52.9    33.3    21.7    14.5

 

Committed tons include both executed contracts and sales where terms largely have been agreed upon with a customer, but for which signed contracts have yet to be executed.

 

The foregoing table does not include an aggregate of 1.5 million tons that we may be required to deliver from 2005 through 2009 upon exercise of rights of customers under executed contracts to buy more coal at predetermined prices.

 

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.

 

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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 is 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 that provide for delivery of coal to electric generating plants operated by FirstEnergy. A 17 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 18 year, 52 million ton coal agreement, entered into in September 2003 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. Both of these agreements include a price re-opener provision every three years. If the parties do not agree on price at that time, the contract will be terminated at the end of the then current year.

 

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. 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, 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 has served as temporary floating storage for coal where land storage is unavailable. Approximately 32% of the coal that we produced was shipped on the inland waterways in 2004.

 

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 five largest producers are estimated by the 2004 National Mining Association Survey to have produced approximately 53% (based on tonnage produced) of the total United States production in 2003. The U.S. Department of Energy reported 1,316 active coal mines in the United States in 2003, 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;

 

    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.

 

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Gas Operations

 

CONSOL Energy primarily 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 1,666 wells, 885 miles of gathering lines and various compression stations at December 31, 2004. Our southwestern Virginia operations control approximately 235,000 acres of gas rights. At December 31, 2004, we reported 1,014.6 billion cubic feet of net proved reserves of gas, of which approximately 36.8% is developed.

 

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, we operate 122 wells, and our December 2004 average daily gross production was approximately 5 million cubic feet per day. At December 31, 2004, we reported 27.8 billion cubic feet of net proved reserves of gas, of which approximately 77% is developed. In addition to the 13 wells drilled in 2004, 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 2004 average daily gross production was approximately 0.5 million cubic feet per day. At December 31, 2004, our portion of proved net gas reserves for this area was 2.4 billion cubic feet, of which 62.4% were developed.

 

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

 

Drilling

 

The total average daily gross rate of production controlled by CONSOL Energy during 2004, was 155.7 million cubic feet. During 2004, 2003 and 2002, we drilled in the aggregate, 235, 251, and 197 development wells, respectively, all of which were productive. The net number of wells for those periods was approximately 228, 244, and 194, 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 Years

Ended December 31,


     2004

   2003

   2002

     Gross

   Net

   Gross

   Net

   Gross

   Net

Virginia

   229    222    237    237    191    191

Northern West Virginia/Southwest Pennsylvania

   6    6    —      —      —      —  

Tennessee

   —      —      14    7    6    3

 

During 2004, 2003 and 2002, we drilled in the aggregate 17, 52, and 34 exploratory wells, respectively. The net number of wells for those periods was 12, 36, and 25, respectively. Some of the 2003 and 2004 wells are still being evaluated or are awaiting completion. Nine of the wells in Northern West Virginia and Southwest Pennsylvania are also awaiting completion. In 2004, three Tennessee area exploration wells drilled in 2002 were

 

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expensed as dry wells. Prior to these wells, we have not had any dry exploration wells. The following table illustrates the exploratory wells by geographic region:

 

Exploration Wells

 

    

For the Years

Ended December 31,


     2004

   2003

   2002

     Gross

   Net

   Gross

   Net

   Gross

   Net

Virginia

   —      —      19    16    15    15

Northern West Virginia/Southwest Pennsylvania

   7    7    7    7    1    1

Tennessee

   10    5    26    13    18    9

 

Production

 

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

 

    

For the Years

Ended December 31,


     2004

   2003

   2002

Coalbed methane (in millions of cubic feet)

   49,876    44,421    41,269

 

Water produced from our Virginia operations, which represents 78% of the total water produced by our gas operations, is hauled to deep wells for disposal. Water from our Northern West Virginia/Southwest Pennsylvania operations is hauled to an independent treatment facility where it is treated and discharged.

 

Average Sales Prices and Lifting Costs

 

The following table sets forth the average sales price, net of hedging transactions, and the average net 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 32 of Notes to Consolidated Financial Statements.

 

     For the Years Ended
December 31,


     2004

   2003

   2002

Average gas sales price (per thousand cubic feet)

   $ 5.00    $ 4.14    $ 3.17

Average net lifting cost (per thousand cubic feet)

   $ 0.51    $ 0.48    $ 0.40

 

Productive Wells and Acreage

 

The following table sets forth, at December 31, 2004, the number of CONSOL Energy’s producing wells, developed acreage and undeveloped acreage.

 

     Gross

   Net

Producing Wells

   1,828    1,801

Developed Acreage

   143,460    142,660

Undeveloped Acreage

   501,404    398,154

 

We drilled 235 development wells in 2004, of which 33 wells were in process at December 31, 2004. 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.

 

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We currently plan to drill approximately 335 wells in 2005. Two hundred and forty of these wells are proposed to be conventional coalbed methane wells drilled into coal seams not yet mined. Fifty-eight of the remaining wells are proposed to be drilled into mine areas to produce gob gas, which is methane gas that has collected in abandoned areas of underground coal mines. Fifteen 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. Twenty-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

 

CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length from a single day to greater than a year. 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. CONSOL Energy has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. In 2004, these cash flow hedges represented 28% of our produced sales volumes at an average price of $5.10 per thousand cubic feet. We intend for these transactions to cover approximately 17% of our estimated 2005 production volume. CONSOL Energy sold 84% of its gas sales volumes in 2004 under fixed priced contracts at an average price of $4.96 per thousand cubic feet compared to 90% of its gas sales volumes under fixed price contracts in 2003 at an average of $3.99 per thousand cubic feet. CONSOL Energy has entered into fixed price gas sales contracts with various marketers representing approximately 63% of total projected 2005 production, at an average price of $4.78 per thousand cubic feet in order to manage price fluctuations and achieve more predictable cash flows. 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 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, 2004.

 

Due to the potential curtailment on portions of the shipment capacity allocated to CONSOL Energy as a result of increased demand for pipeline use on the Columbia Gas Transmission Corporation’s interstate gas pipeline (the pipeline), CONSOL Energy purchased firm transportation capacity on the pipeline. The first firm transportation arrangement covered the May 2004 through October 2004 period. CONSOL Energy expects to experience potential production curtailments through spring and summer of 2005 due to capacity constraints continuing on the pipeline. In November 2004, CONSOL Energy engaged in an extended firm transportation for use on the pipeline which covers the November 2004 through October 2006 period to offset a portion of the expected impact from the estimated curtailment. As of February 2005, purchased fixed capacity on the pipeline represents approximately 35% of our projected production for the same period. CONSOL Energy also participates in the short-term firm capacity markets to manage flows as market conditions dictate. In addition, in order to satisfy obligations to certain customers, we purchased gas from and sold gas to other gas suppliers, which increased our revenues and our costs.

 

The hedging strategy and information regarding derivative instruments used are outlined in item 7A, “Qualitative and Quantitative Disclosures About Market Risk”, and in Note 27 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. 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

 

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our 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 recoverable 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. Proved developed and proved undeveloped gas reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Independent petroleum engineers with Ralph E. Davis Associates, Inc. and Schlumberger Data and Consulting Service, prepared the reserve estimates presented below. 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,

     2004

   2003

   2002

     Consolidated
Operations


   Equity
Affiliates


   Consolidated
Operations


   Equity
Affiliates


   Consolidated
Operations


   Equity
Affiliates


Estimated proved developed reserves

   395,152    1,489    352,935    843    329,687    559

Estimated proved undeveloped reserves

   647,251    896    649,865    738    630,259    —  

Total estimated proved developed and undeveloped reserves

   1,042,403    2,385    1,002,800    1,581    959,946    559

 

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,

     2004

   2003

   2002

Future net cash flows (net of income tax)

   $ 2,872,571    $ 2,708,797    $ 2,037,696

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

   $ 1,029,538    $ 1,011,186    $ 735,181

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

   $ 1,655,232    $ 1,556,866    $ 1,089,900

 

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

 

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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 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. This facility is used for meeting peak load demands. The facility is in southwest Virginia and uses coalbed methane gas that we produce. In 2004, 2003 and 2002, the facility operated for a total of 33,340, 17,610 and 34,540 megawatt hours, respectively, and did not have a significant effect on earnings in any period.

 

Land Resources

 

CONSOL Energy is developing property assets previously used primarily to support its coal operations or property assets currently 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;

 

    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 11 customer service centers nationwide. 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 54% of Fairmont Supply’s sales in 2004 were made to CONSOL Energy’s mines.

 

Terminal Services

 

In 2004, approximately 5.5 million tons of coal were shipped through CONSOL Energy’s exporting terminal in the Port of Baltimore. Approximately 23% 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.

 

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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 2004, our river vessels transported a total of 10.3 million tons of coal, of which 7.9 million tons was produced by CONSOL Energy mines.

 

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 all of 2004. 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.

 

Employee and Labor Relations

 

At December 31, 2004, CONSOL Energy had 6,982 employees, 3,092 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 electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for CONSOL Energy’s coal and gas products. 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 increasingly 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.

 

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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 $1.3 million, $1.4 million and $1.4 million for the twelve months ended December 31, 2004, 2003 and 2002, respectively. CONSOL Energy expects to have capital expenditures of $15.1 million for 2005 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.

 

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 $441 million at December 31, 2004. These obligations are unfunded at December 31, 2004.

 

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, results of operations and cash flows.

 

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

 

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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 $196 million at December 31, 2004. These obligations are unfunded. The amount we expensed in the twelve months ended December 31, 2004, was $69 million, while the related cash payment for this liability was $53 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.

 

CONSOL Energy changed its method of accounting for workers’ compensation effective January 1, 2004. Prior to the change, we recorded our workers’ compensation liability on an undiscounted basis. Under the new method, we record the liability on an actuarially determined basis, which uses various assumptions, including discount rate and future cost trends. CONSOL Energy believes this change was preferable since it aligns the accounting with our other long-term employee benefit obligations, which are recorded on a discounted basis. Additionally, it provides a better comparison with our industry peers, the majority of which record the workers’ compensation liability on a discounted basis.

 

The change was 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 resulted in an income adjustment of approximately $83 million, net of approximately $53 million of deferred tax expense.

 

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. The cost for this plan is recognized as expense when payments are assessed. We made payments of $53 million ($50 million expensed and $3 million capitalized) for such health benefits in the twelve months ended December 31, 2004. Based on current law and available information, at December 31, 2004, CONSOL Energy’s obligation is estimated at approximately $483 million.

 

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,

 

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    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 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.

 

Our reclamation and mine-closing liabilities, including the current portion, were $365 million at December 31, 2004. 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, 2004 was $23 million, while the related cash payment for such liability during the same period was $39 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.

 

Clean Air Act and Related New Regulations

 

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

 

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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 (“NAAQS”) for particulate matter which may require some states to change existing implementation plans. As a result of the NAAQS revisions, many areas of the country were reclassified from attainment to non-attainment for fine particulate or ozone in 2004. 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 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.

 

CONSOL Energy believes it has obtained all necessary permits under the Clean Air Act. The expiration dates of these permits range from October 1, 2005 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 $58,000, $104,000 and less than $19,000 for 2004, 2003 and 2002, respectively.

 

The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal fired 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 affect 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 and nitrogen dioxide emissions from electric power plants.

 

Further sulfur dioxide emission reductions will be required by proposed Clear Skies legislation or Clean Air Interstate Rules (“CAIR”), one of which likely will be enacted in 2005. 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. Clear Skies legislation and CAIR rules will both significantly reduce sulfur dioxide emission allowances available to electric power plants. As limits are ratcheted down, very few coals are truly “compliance” coal and the installation of environmental control technology in the form of scrubbers becomes an economic option. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent and timing to which power generators install scrubbers could materially affect our business.

 

Other new and proposed reductions in emissions of mercury, nitrogen oxides, particulate matter or various greenhouse gases may require the installation of additional control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels. For example, in 2004, the United States Environmental Protection Agency (EPA) required the reduction of nitrogen oxide emissions in 22 eastern states and the District of Columbia and will also 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.

 

The Clean Air Act requires that standards be developed for sources of hazardous air pollutants. For instance, rules regulating mercury emissions from coal-fired power plants were proposed by the EPA on January 30, 2004, and are expected to be finalized in 2005 either through Clear Skies legislation or the EPA regulatory process. These proposed rules, when finalized, will establish mercury emissions standards for both new and existing coal-fired power plants. Two significantly different rules were proposed for comment, with one proposal imposing much stricter emission limits on power plants burning bituminous coal than subbituminous coal. The other proposal also imposes more stringent emission limits on bituminous coal compared to subbituminous coal, but the differences are considerably narrower. Conversely, power plants burning bituminous coal that have selective catalytic reduction (SCR) systems installed for nitrogen oxide (NOx) emissions control and scrubbers for sulfur dioxide emissions control have been found to achieve significant mercury reduction also. This same emission

 

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control equipment does not produce high levels of mercury emission reduction in plants burning subbituminous coal. 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. Final regulations could favor or disadvantage bituminous coal with respect to mercury emissions control, depending on the version enacted.

 

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 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 positively or negatively impact their demand for CONSOL Energy coal.

 

Also, numerous proposals have been made at the international, national and state levels that are intended to limit or capture emissions of greenhouse gases, such as carbon dioxide. If comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States or individual states, it may affect the use of fossil fuels, particularly 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, financial condition and cash flows.

 

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 1991, CONSOL Energy was named a potentially responsible party related to the Buckeye Landfill Superfund Site and accordingly recognized an estimated liability for remediation of this site of which $2.7 million remained as of March 31, 2004. In April 2004, CONSOL Energy entered into an Environmental Liability Transfer and Indemnity Agreement that transferred our liability related to the Buckeye Landfill Superfund Site to another party. The transaction resulted in the reversal of the remaining liability and the recognition of $1.4 million of income. Also, CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under Superfund

 

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legislation with respect to the Ward Transformer site in Wake County, North Carolina. The EPA has also identified 38 other PRPs for the Ward Transformer site. No remedial approaches have been agreed to date between the EPA and PRPs. No agreement on an allocation of costs between PRPs and EPA has been reached to date. The estimated total remediation cost for all responsible parties, based on preliminary information available at the time, is approximately $7.5 million. Based on preliminary information received to date, CONSOL Energy estimates its portion of this claim to be approximately 20% of the total. Accordingly, a liability of $1.5 million was recorded in the three months ended December 31, 2004. CONSOL Energy has made no payments to date related to the remediation of this site.

 

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, financial condition and cash flows.

 

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, 2004. Emery Mine’s asset for advance mining royalty related to the federal leases was $0.5 million at December 31, 2004. 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

 

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“unbundled,” from the pipelines’ sales of gas. Also, Order No. 636 requires pipeline operators to provide open 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.

 

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 25,100 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.

 

CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency, or EPA, that it is a potentially responsible party, or PRP, under Superfund legislation with respect to the Ward Transformer site in Wake County, North Carolina. The EPA has also identified 38 other PRPs for the Ward Transformer site. No remedial approaches have been agreed to between the EPA and PRPs. No agreement on an allocation of costs between PRPs and EPA has been reached to date. The estimated total remediation cost for all responsible parties, based on preliminary information, is approximately $7.5 million. Based on preliminary information received to date, CONSOL Energy estimates its portion of this claim to be approximately 20% of the total remediation cost.

 

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 it’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. Another class action complaint has 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 that complaint. CONSOL Energy management believes those claims are without merit, and, accordingly, we have not accrued any liability associated with those claims.

 

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.

 

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

 

None.

 

Executive Officers of CONSOL Energy

 

The following is a list of CONSOL Energy’s executive officers, their ages as of February 15, 2005 and their positions and offices held with CONSOL Energy.

 

Name


   Age

  

Position


J. Brett Harvey

   54    President and Chief Executive Officer and Director

Peter B. Lilly

   56    Chief Operating Officer—Coal

Ronald E. Smith

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

William J. Lyons

   56    Chief Financial Officer

 

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. Mr. Smith joined CONSOL Energy in 1972.

 

William J. Lyons has been 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. Mr. Lyons joined CONSOL Energy in 1976.

 

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PART II

 

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities.

 

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, 2003

                    

Quarter Ended March 31, 2003

   $ 18.01    $ 14.55    $ 0.14

Quarter Ended June 30, 2003

   $ 24.61    $ 15.65    $ 0.14

Quarter Ended September 30, 2003

   $ 22.95    $ 18.18    $ 0.14

Quarter Ended December 31, 2003

   $ 26.80    $ 18.67    $ 0.14

Twelve Month Period Ended December 31, 2004

                    

Quarter Ended March 31, 2004

   $ 30.01    $ 20.24    $ 0.14

Quarter Ended June 30, 2004

   $ 36.73    $ 24.85    $ 0.14

Quarter Ended September 30, 2004

   $ 39.25    $ 29.80    $ 0.14

Quarter Ended December 31, 2004

   $ 43.90    $ 32.11    $ 0.14

 

As of February 7, 2005, there were approximately 23,000 holders of record of our common stock. The computation of the approximate number of shareholders is based upon a broker search.

 

On January 28, 2005, CONSOL Energy’s board of directors declared a dividend of $0.14 per share, payable on February 25, 2005, to shareholders of record on February 10, 2005.

 

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 11. Executive Compensation for information relating to CONSOL Energy’s equity compensation plans.

 

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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, 2004, 2003, 2002, twelve months ended June 30, 2001 and June 30, 2000, and the six months ended December 31, 2001 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 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 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.

 

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STATEMENT OF INCOME DATA

(In thousands except per share data)

    Years Ended December 31,

    Six Months
Ended
December 31,


   

Twelve Months

Ended June 30,


 
    2004

    2003

    2002

    2001

    2001

    2001

    2000

 
    (Unaudited)  

Revenue and Other Income:

                                                       

Sales(A)

  $ 2,580,253     $ 2,042,851     $ 2,003,345     $ 2,095,463     $ 964,460     $ 2,123,202     $ 2,094,850  

Freight(A)

    110,175       114,582       134,416       159,029       70,314       160,940       165,934  

Other income

    86,321       65,033       45,837       64,526       31,223       70,457       64,359  
   


 


 


 


 


 


 


Total Revenue and Other Income

    2,776,749       2,222,466       2,183,598       2,319,018       1,065,997       2,354,599       2,325,143  

Costs:

                                                       

Cost of goods sold and other operating charges

    2,001,010       1,624,016       1,543,189       1,585,686       761,146       1,554,867       1,498,982  

Freight expense

    110,175       114,582       134,416       159,029       70,314       160,940       165,934  

Selling, general and administrative expense

    72,870       77,571       65,888       61,155       31,493       63,043       62,164  

Depreciation, depletion and amortization

    280,397       242,152       262,873       243,588       120,039       243,272       249,877  

Interest expense

    31,429       34,451       46,213       43,356       16,564       57,598       55,289  

Taxes other than income

    198,305       160,209       172,479       160,954       80,659       158,066       174,272  

Export sales excise tax resolution

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

Restructuring costs

    —         3,606       —         —         —         —         12,078  
   


 


 


 


 


 


 


Total Costs

    2,694,186       2,255,973       2,224,021       2,135,648       1,085,617       2,114,264       2,218,596  
   


 


 


 


 


 


 


Earnings (loss) before income taxes

    82,563       (33,507 )     (40,423 )     183,370       (19,620 )     240,335       106,547  

Income taxes (benefits)

    (32,646 )     (20,941 )     (52,099 )     32,164       (20,679 )     56,685       (493 )
   


 


 


 


 


 


 


Earnings (loss) before cumulative effect of change in accounting principle

    115,209       (12,566 )     11,676       151,206       1,059       183,650       107,040  
   


 


 


 


 


 


 


Cumulative effect of changes in accounting for workers’ compensation liability, net of income taxes of $53,080

    83,373       —         —         —         —         —         —    

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)

  $ 198,582     $ (7,798 )   $ 11,676     $ 151,206     $ 1,059     $ 183,650     $ 107,040  
   


 


 


 


 


 


 


Earnings per share from continuing operations

                                                       

Basic

  $ 1.28     $ (0.15 )   $ 0.15     $ 1.92     $ 0.01     $ 2.34     $ 1.35  
   


 


 


 


 


 


 


Dilutive

  $ 1.26     $ (0.15 )   $ 0.15     $ 1.91     $ 0.01     $ 2.33     $ 1.35  
   


 


 


 


 


 


 


Earnings per share from net income

                                                       

Basic(B)

  $ 2.20     $ (0.10 )   $ 0.15     $ 1.92     $ 0.01     $ 2.34     $ 1.35  
   


 


 


 


 


 


 


Dilutive(B)

  $ 2.18     $ (0.10 )   $ 0.15     $ 1.91     $ 0.01     $ 2.33     $ 1.35  
   


 


 


 


 


 


 


Weighted average number of common shares outstanding:

                                                       

Basic

    90,230,693       81,732,589       78,728,560       78,671,821       78,699,732       78,613,580       79,499,576  
   


 


 


 


 


 


 


Dilutive

    91,199,945       81,732,589       78,834,023       78,964,557       78,920,046       78,817,935       79,501,326  
   


 


 


 


 


 


 


Dividend per share

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


 


 


 


 


 


 


 

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Table of Contents

BALANCE SHEET DATA

(In thousands)

     At December 31,

    At June 30,

 
     2004

    2003

    2002

    2001

    2001

    2000

 

Working capital (deficiency)

   $ (235,316 )   $ (358,459 )   $ (191,596 )   $ (70,505 )   $ (368,118 )   $ (375,074 )

Total assets

     4,195,611       4,318,978       4,293,160       4,298,732       3,894,971       3,866,311  

Short-term debt

     5,060       68,760       204,545       77,869       360,063       464,310  

Long-term debt (including current portion)

     429,645       495,242       497,046       545,440       303,561       307,362  

Total deferred credits and other liabilities

     2,595,345       2,757,130       2,828,249       2,913,763       2,378,323       2,358,725  

Stockholders’ equity

     469,021       290,637       162,047       271,559       351,647       254,179  

 

OTHER OPERATING DATA

(Unaudited)

    

Twelve Months

Ended December 31,


   

Six Months

Ended

December 31,


    Twelve Months
Ended June 30,


 
     2004

    2003

    2002

    2001

    2001

    2001

    2000

 

Coal:

                                                        

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

     69,537       63,962       67,308       76,503       35,587       77,322       78,714  

Tons produced (in thousands)(D)

     67,745       60,388       66,230       73,705       34,355       71,858       73,073  

Productivity (tons per manday)(D)

     40.51       41.26       40.18       39.95       37.15       42.21       44.23  

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

   $ 27.54     $ 26.24     $ 24.73     $ 22.21     $ 23.73     $ 21.35     $ 20.00  

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

   $ 30.06     $ 27.61     $ 26.76     $ 24.66     $ 25.02     $ 23.93     $ 23.66  

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

     4,509       4,158       4,275       4,365       4,365       4,411       4,461  

Number of mining complexes (at period end)

     17       20       22       27       27       23       22  

Gas:

                                                        

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

     48.60       44.46       41.30       33.92       17.61       29.75       14.20  

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

     5.41     $ 4.31     $ 3.17     $ 4.04     $ 2.63     $ 5.19     $ 3.01  

Average costs ($ per mcf)(D)

     2.45     $ 2.35     $ 2.18     $ 2.38     $ 2.27     $ 2.16     $ 1.60  

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

     1,045       1,004       961       1,023       1,023       677       653  

CASH FLOW STATEMENT DATA

(In thousands)

 

 

    

Twelve Months

Ended December 31,


   

Six Months

Ended

December 31,


    Twelve Months
Ended June 30,


 
     2004

    2003

    2002

    2001

    2001

    2001

    2000

 
                       (Unaudited)                    

Net cash provided by operating activities

   $ 358,091     $ 381,127     $ 329,556     $ 347,356     $ 93,084     $ 435,839     $ 295,028  

Net cash used in investing activities

     (400,542 )     (204,614 )     (339,936 )     (114,160 )     (11,598 )     (233,321 )     (299,554 )

Net cash (used in) provided by financing activities

     42,360       (181,517 )     6,315       (228,184 )     (82,529 )     (194,074 )     (10,852 )

 

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Table of Contents

OTHER FINANCIAL DATA

(Unaudited)

(In thousands)

Capital expenditures

   $ 410,611    $ 290,652     $ 295,025     $ 266,825    $ 162,700     $ 213,132    $ 142,270

EBIT(H)

     108,616      (5,354 )     (1,230 )     194,330      (2,132 )     262,052      156,165

EBITDA(H)

     389,013      236,798       261,643       437,918      117,907       505,324      406,042

Ratio of earnings to fixed charges(I)

     3.14      —         —         4.59      —         4.54      2.70

(A) See Note 29 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 969,252, none, 105,463 and 292,736 for the twelve months ended December 31, 2004, December 31, 2003, December 31, 2002 and 2001; 220,314 for the six months ended December 31, 2001; and 204,335 and 1,750 for twelve months ended June 30, 2001 and 2000.
(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: 2.1 million tons in the twelve months ended December 31, 2004; 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; 2.7 million tons in the twelve months ended June 30, 2001; and 3.5 million tons in the twelve months ended June 30, 2000. Sales of coal produced by equity affiliates were: 0.1 million tons in the twelve months ended December 31, 2004; 1.0 million tons in the twelve months ended December 31, 2003; 1.6 million tons in the twelve months ended December 31, 2002; 1.6 million tons in the twelve months ended December 31, 2001; 0.9 million tons in the six months ended December 31, 2001; and 0.7 million tons in the twelve months ended June 30, 2001. No sales from equity affiliates occurred in previous periods presented.
(D) For entities that are not wholly owned but in which CONSOL Energy owns at least 50% equity interest, includes a percentage of their net production, sales or reserves equal to CONSOL Energy’s percentage equity ownership. For coal, Glennies Creek Mine is reported as an equity affiliate through February 2004. 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 2004, 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 .20 bcf in the twelve months ended December 31, 2004, .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 coal 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.

 

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Table of Contents
(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 a 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,


 

(Unaudited))

(In thousands)

   2004

    2003

    2002

    2001

    2001

    2001

    2000

 

Net Income (Loss)

   $ 198,582     $ (7,798 )   $ 11,676     $ 151,206     $ 1,059     $ 183,650     $ 107,040  

Add: Interest expense

     31,429       34,451       46,213       43,356       16,564       57,598       55,289  

*Less: Interest income

     (5,376 )     (5,602 )     (5,738 )     (5,990 )     (3,734 )     (4,817 )     (5,671 )

*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 Workers’ Compensation Liability, net of Income Taxes of $53,080

     (83,373 )     —         —         —         —         —         —    

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)

     (32,646 )     (20,941 )     (52,099 )     32,164       (20,679 )     56,685       (493 )
    


 


 


 


 


 


 


Earnings (Loss) before interest and taxes (EBIT)

     108,616       (5,354 )     (1,230 )     194,330       (2,132 )     262,052       156,165  

Add: Depreciation, depletion and amortization

     280,397       242,152       262,873       243,588       120,039       243,272       249,877  
    


 


 


 


 


 


 


Earnings before interest, taxes and depreciation, depletion and amortization (EBITDA)

   $ 389,013     $ 236,798     $ 261,643     $ 437,918     $ 117,907     $ 505,324     $ 406,042  
    


 


 


 


 


 


 



(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.

 

40


Table of Contents
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

General

 

CONSOL Energy had net income of $199 million for the twelve months ended December 31, 2004 compared to a net loss of $8 million for the twelve months ended December 31, 2003. Net income for 2004 was improved due to increased coal and gas sales volume and increased average sales prices for both coal and gas. Pre-tax earnings also improved $21 million due to the recognition of the favorable effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003. Net income also improved due to the gain on sale of the stock of our wholly owned subsidiary, CNX Australia Pty Limited, to certain affiliates of AMCI, Inc. In addition, net income improved due to an increased tax benefit related to the release of $15 million of contingent income tax liability resulting from the settlement of the federal, state and foreign income tax audits of prior years. Also, additional income resulted from the cumulative effect of change in accounting related to workers’ compensation in 2004. These increases in net income were offset, in part, by higher cost of goods sold attributable to higher sales volumes of coal and gas and to higher unit costs for coal and gas produced. Higher cost per ton of coal produced was due mainly to increased labor, supply and Combined Fund premiums per unit produced. Higher cost of gas produced was attributable to increased royalty cost and cost of firm transportation incurred by the gas operations. Increases in net income were also offset, in part, by $32 million of accelerated depreciation, depletion and amortization taken for equipment and facilities at Rend Lake and other idled mining operations. While there are no current plans for the use of the equipment or facilities, these mines have existing reserves that could be accessed from other locations or through new facilities.

 

Total coal sales for the twelve months ended December 31, 2004 were 69.5 million tons, including our portion of sales by equity affiliates, of which 67.4 million tons 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 64.0 million tons for the twelve months ended December 31, 2003, of which 61.5 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 increase in tons sold was due primarily to the Loveridge Mine resuming production in March 2004 and increased production at the McElroy Mine. Loveridge experienced a fire in February 2003 while it was in the process of developing a new underground area and therefore it had no production in 2003. McElroy production increased due to the addition of a second longwall mining unit during 2004 and improved mining conditions compared to 2003. Several other mines increased production in 2004 compared to 2003. CONSOL Energy produced 67.7 million tons, including our portion of production at equity affiliates in 2004 compared to 60.4 million tons, including our portion of production at equity affiliates in 2003.

 

Sales of coalbed methane gas, including our share of the sales from equity affiliates were 55.5 billion cubic feet in 2004 compared to 50.8 billion cubic feet in 2003. 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 $5.05 per thousand cubic feet in 2004 compared to $4.16 per thousand cubic feet in 2003. We believe that the 2004 gas market price increases were largely attributable to continued concerns over levels of North American gas production, as well as increased oil prices and the economic recovery which resulted in greater electricity use in our principal markets.

 

CONSOL Energy restated first quarter 2004 net income by approximately $2.2 million to reflect the recognition of the favorable effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 as of March 8, 2004 in accordance with authoritative accounting guidance.

 

CONSOL Energy’s Buchanan Mine, located near Keen Mountain, Virginia, experienced a large rock fall behind its longwall mining section on February 14, 2005. While caving behind the longwall is a normal part of the mining process, the size of this cave-in created a large air pressure wave that disrupted ventilation and also caused an ignition of methane gas in the area. CONSOL Energy has temporarily sealed the mine in order to extinguish the localized fire that developed after the ignition. Based on a review of gas samples from the mine

 

41


Table of Contents

that have been collected and analyzed by CONSOL Energy as well as by state and federal safety officials, it has been determined that the fire exists in a localized area adjacent to the longwall mining system. In addition to sealing the mine, CONSOL Energy plans to drill several boreholes from the surface into the area of the mine where the problem is believed to be located. An initial borehole drilling has penetrated the mine at the place where a mine fire was suspected to have started. Video equipment lowered into the borehole to visually inspect the area shows that the location is clear of any fire or smoke. Various materials, including nitrogen foam and water will be pumped into the area in order to accelerate the process of creating an inert environment within the mine to extinguish the fire. The mine is currently idle and will not produce coal while the mine is sealed. Gas production from this area may also be curtailed due to the idling of the Buchanan longwall. Gas production from this area averaged 23.6 thousand cubic feet per day in January 2005.

 

Results of Operations

 

Twelve Months Ended December 31, 2004 compared with Twelve Months Ended December 31, 2003 (Amounts reported in millions)

 

Net Income

 

Net income changed primarily due to the following items:

 

     2004

   2003

   

Dollar

Variance


   

Percentage

Change


 

Coal Sales—Produced and Purchased

   $ 2,087    $ 1,758     $ 329     18.7  %

Gas Sales—Produced

     275      208       67     32.2  %

Gas Sales—Purchased

     112      —         112     100.0  %

Other Sales and other income

     303      256       47     18.4  %
    

  


 


     

Total Revenue and other income

     2,777      2,222       555     25.0  %

Coal Cost of Goods Sold—Produced and Purchased

     1,533      1,310       223     17.0  %

Produced Gas Cost of Goods Sold

     105      84       21     25.0  %

Purchased Gas Cost of Goods Sold

     113      —         113     100.0  %

Other Cost of Goods Sold

     250      230       20     8.7  %
    

  


 


     

Total Cost of Goods Sold

     2,001      1,624       377     23.2  %

Depreciation, Depletion and Amortization

     280      242       38     15.7  %

Taxes Other Than Income

     198      160       38     23.8  %

Other

     215      230       (15 )   (6.5 )%
    

  


 


     

Total Costs

     2,694      2,256       438     19.4  %

Earnings (Loss) before income tax and cumulative effect of change in accounting principle

     83      (34 )     117     344.1  %

Income Taxes

     33      21       12     57.1  %
    

  


 


     

Earnings (Loss) before Cumulative effect of change in accounting

     116      (13 )     129     992.3  %

Cumulative effect of change in accounting

     83      5       78     1,560.0  %
    

  


 


     

Net Income (Loss)

   $ 199    $ (8 )   $ 207     2,587.5  %
    

  


 


     

 

Net income for 2004 was improved due to increased coal and gas sales volumes and increased average sales prices for both coal and gas. Pre-tax earnings also improved $21 million due to the recognition of the favorable effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 as of March 8, 2004 in accordance with accounting guidance. Also, net income was improved $14 million due to the gain on sale of the stock of CONSOL Energy’s wholly owned subsidiary, CNX Australia Pty Limited, to certain affiliates of AMCI, Inc. In addition, net income improved due to an increased tax benefit related to the release of $15 million of contingent income tax liabilities resulting from the settlement of the federal, state and foreign income tax audits of prior years. Also, an additional $83 million of income from the cumulative effect of change in accounting related to workers’ compensation was recognized in 2004 compared to $5 million of income for mine

 

42


Table of Contents

closing, perpetual care and gas well closing costs recognized in 2003. These increases in net income were offset, in part, by higher cost of goods sold attributable to higher sales volumes of coal and gas and to higher unit costs for coal and gas produced. Higher cost per ton of coal produced was due mainly to increased labor, supply and Combined Fund premiums per unit produced. Higher cost of gas produced was attributable to increased royalty cost and cost of firm transportation incurred by the gas operations. Increases in net income were also offset, in part, by $32 million of accelerated depreciation, depletion and amortization taken for equipment and facilities at Rend Lake and other idled mining operations. While there are no current plans for the use of the equipment or facilities, these mines have existing reserves that could be accessed from other locations or through new facilities.

 

Revenue

 

Revenue and other income increased due to the following items:

 

     2004

   2003

  

Dollar

Variance


   

Percentage

Change


 

Sales

                            

Produced Coal

   $ 2,008    $ 1,683    $ 325        

Produced Coal—Related Party

     —        1      (1 )      
    

  

  


     

Total Produced Coal

     2,008      1,684      324     19.2  %

Purchased Coal

     79      74      5     6.8  %

Produced Gas

     275      208      67     32.2  %

Purchased Gas

     112      —        112     100.0  %

Industrial Supplies

     79      63      16     25.4  %

Other

     27      14      13     92.9  %
    

  

  


     

Total Sales

     2,580      2,043      537     26.3  %

Freight Revenue

     110      114      (4 )      

Freight—Related Party

     —        1      (1 )      
    

  

  


     

Total Freight

     110      115      (5 )   (4.3 )%

Other Income

     87      64      23     35.9  %
    

  

  


     

Total Revenue and Other Income

   $ 2,777    $ 2,222      555     25.0  %
    

  

  


     

 

The increase in Company produced coal sales revenue was due mainly to higher volumes sold during the period-to-period comparison and an increase in average sales price per ton.

 

     2004

   2003

   Variance

  

Percentage

Change


 

Produced Tons Sold (in millions)

     67.3      60.9      6.4    10.5 %

Average Sales Price Per Ton

   $ 29.84    $ 27.67    $ 2.17    7.8 %

 

The increase in tons sold was due primarily to the Loveridge Mine resuming production in March 2004 and increased production at the McElroy Mine. Loveridge experienced a fire in February 2003 while it was in the process of developing a new underground area and therefore it had no production in 2003. McElroy production increased due to the addition of a second longwall mining unit during 2004 and improved mining conditions compared to 2003. The increase in company produced coal sales revenue was also attributable to the increase in average sales price per ton sold. The increase in average sales price reflects stronger prices negotiated in 2003 and an overall improvement in 2004 prices in the eastern coal market for coals sold to domestic and foreign utilities and for metallurgical coal.

 

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Table of Contents

The increase in Company purchased coal sales revenue was due to higher average sales price per ton of purchased coal, offset, in part, by a decrease in tons of purchased coal sold.

 

     2004

   2003

   Variance

   

Percentage

Change


 

Purchased Tons Sold (in millions)

     2.1      2.4      (0.3 )   (12.5 )%

Average Sales Price Per Ton

   $ 37.60    $ 31.16    $ 6.44     20.7  %

 

The increased average sales price is primarily due to some of the purchased coal tons being sold in higher priced export and metallurgical markets. Increased revenue from higher average sales prices were offset by lower sales volumes in 2004 compared to 2003.

 

The increase in gas sales revenue was primarily due to a higher average sales price per thousand cubic feet and increased volumes sold in 2004 compared to 2003.

 

     2004

   2003

   Variance

  

Percentage

Change


 

Produced Gas Gross Sales Volumes (in billion cubic feet)

     54.6      50.0      4.6    9.2 %

Average Sales Price Per thousand cubic feet

   $ 5.04    $ 4.16    $ 0.88    21.2 %

 

We believe that the 2004 gas market price increases were largely driven by continued concerns over levels of North American gas production, as well as increased oil prices and the economic recovery which resulted in greater electricity use in our principal markets. CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length from a single day to greater than a year. CONSOL Energy has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. In 2004, these financial cash flow hedges represented 28% of our produced gas sales volumes at an average price of $5.10 per thousand cubic feet. We currently intend to cover approximately 17% of our estimated 2005 production volume with gas swap transactions. CONSOL Energy sold 84% of its produced gas sales volumes in 2004 under fixed priced contracts at an average price of $4.96 per thousand cubic feet compared to 90% of its gas sales volumes under fixed price contracts in 2003 at an average price of $3.99 per thousand cubic feet. Higher sales volumes in 2004 were a result of wells coming on-line from the ongoing drilling program, which allowed CONSOL Energy to take advantage of increased prices. CONSOL has entered into fixed price gas sales contracts with various marketers, representing approximately 63% of total projected 2005 production, at an average price of $4.78/mcf in order to manage price fluctuations and achieve more predictable cash flows.

 

Due to the potential curtailment on portions of the shipment capacity allocated to CONSOL Energy as a result of increased demand for pipeline use on the Columbia Gas Transmission Corporation’s interstate gas pipeline, referred to as the pipeline, CONSOL Energy purchased firm transportation capacity on the pipeline during 2004. The first firm transportation arrangement covered the May 2004 through October 2004 period. CONSOL Energy expects to experience potential production curtailments through spring and summer of 2005 due to capacity constraints continuing on the pipeline. In November 2004, CONSOL Energy entered into an extended firm transportation arrangement for fixed capacity on the pipeline to offset a portion of the expected impact from the estimated curtailments. This arrangement covers the November 2004 through October 2006 period. As of February 2005, the purchased fixed capacity on the pipeline represents approximately 35% of our projected production for the same period. In addition, in order to satisfy obligations to certain customers, we purchased gas from and sold gas to other gas suppliers, which increased our revenues and our costs.

 

     2004

   2003

   Variance

  

Percentage

Change


 

Purchased Gas Sales Volumes (in billion cubic feet)

     17.5    —        17.5    100.0 %

Average Sales Price Per thousand cubic feet

   $ 6.39    —      $ 6.39    100.0 %

 

The increase in revenues from the sale of industrial supplies was due to increased sales volumes and prices.

 

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The increase in other sales is primarily attributable to higher through put of outside coal volumes through our Baltimore terminal.

 

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.

 

     2004

    2003

   

Dollar

Variance


   

Percentage

Change


 

Gain on Sale of Assets

   $ 41     $ 23     $ 18     78.3  %

Royalty Income

     19       16       3     18.8  %

Harbor Maintenance Fee Refund

     —         3       (3 )   (100.0 )%

Equity in Loss of Affiliates

     (4 )     (9 )     5     55.6  %

Other Miscellaneous

     31       31       —       —    
    


 


 


     

Total Other Revenue

   $ 87     $ 64     $ 23     35.9  %
    


 


 


     

 

The 2004 gain on sale of assets is due mainly to CONSOL Energy’s sale of stock in its wholly owned subsidiary, CNX Australia Pty Limited, to certain affiliates of AMCI, Inc. for $28 million. Certain affiliates of AMCI, Inc. also assumed 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, owned 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. The sale was completed on February 25, 2004 and resulted in a pre-tax gain of approximately $14 million. The gain on sale of assets in 2004 is also related to the assignment of certain coal leases, conveyance of associated surface property, the transfer of related mining permits and the related liabilities for a location in southern West Virginia that resulted in a pre-tax gain of approximately $7 million. The additional gain on sale of assets in 2004 is related to the sale of several previously closed operations and the sale of surplus equipment. The 2003 gain on sale of assets primarily was related to the expiration in 2003 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 has increased due primarily to third parties producing additional tonnage and gas volumes from CONSOL owned property in the period-to-period comparison.

 

Other income for 2003 included a $3 million harbor maintenance fee refund received from the federal government for prior claims related to harbor maintenance fees imposed by the Federal statute that was subsequently declared unconstitutional. These claims were pursued since 1991, and we do not expect other refunds related to these claims.

 

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The improvement in equity losses of affiliates is primarily attributable to CONSOL Energy’s equity interest in the losses of Glennies Creek mine in 2003. CONSOL Energy’s interest in this mine was sold in February 2004.

 

Costs

 

     2004

   2003

  

Dollar

Variance


   

Percentage

Change


 

Cost of Goods Sold and Other Charges:

                            

Produced Coal

   $ 1,457    $ 1,238    $ 219     17.7  %

Purchased Coal

     76      72      4     5.6  %

Produced Gas

     105      84      21     25.0  %

Purchased Gas

     113      —        113     100.0  %

Industrial Supplies

     94      66      28     42.4  %

Closed and Idle Mines

     72      62      10     16.1  %

Other

     84      102      (18 )   (17.6 )%
    

  

  


     

Total Cost of Goods Sold

   $ 2,001    $ 1,624    $ 377     23.2  %
    

  

  


     

 

Increased cost of goods sold and other charges for company produced coal was due mainly to the increased produced tons sold and an increase in the average cost per ton of produced coal sold.

 

     2004

   2003

   Variance

  

Percentage

Change


 

Produced Tons Sold (in millions)

     67.3      60.9      6.4    10.5 %

Average Cost of Goods Sold and Other Charges Per Ton

   $ 21.64    $ 20.34    $ 1.30    6.4 %

 

Produced tons sold increased due primarily to the Loveridge Mine resuming production in March 2004 and increased production at the McElroy Mine. Loveridge experienced a fire in February 2003 while it was in the process of developing a new underground area and therefore this location had no production in 2003. McElroy production increased due to the addition of a second longwall mining unit during 2004 and improved mining conditions compared to 2003. Several other mines increased production in 2004 compared with 2003. Average cost of goods sold and other charges per ton also increased in 2004 compared to 2003. This increase was attributable to higher supply costs and labor per unit produced. Increased supply costs were related to the higher costs of materials, especially metal products, used in the mining process experienced in 2004 compared to 2003. Increased labor and supply costs were also attributable to additional continuous miner shifts in 2004. Continuous mining machines are used to mine the coal reserve in such a way that large, rectangular blocks of coal, called panels, are delineated underground in preparation for mining by larger more efficient longwall machines in mines equipped with these systems. Typically, mines attempt to delineate more than one panel in advance so that as the longwall machine completes the extraction of the coal in one panel, it can move without delay to another prepared panel. Continuous mining machines are more labor intensive and use more supplies per ton of coal produced than longwall mining systems. Also, CONSOL Energy production from non-longwall mines required additional continuous mining machine shifts to maintain prior year production levels at these locations. Increased average cost per ton was also due to increased Combined Fund premiums related to a premium differential announced by the Social Security Administration for the past eleven plan years for beneficiaries assigned to CONSOL Energy. The increase was approximately $28 million for the plan year beginning October 1, 2003, of which all has been expensed from October 1, 2003 through September 30, 2004. Approximately $21 million of expense was recognized in 2004. These increases in costs per ton were offset, in part, by reduced other post-employment benefits due to the recognition of the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 in 2004.

 

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Purchased coal cost of goods sold and other charges increased due primarily to higher average cost per ton, offset, in part, by reduced volumes of purchased coal sold.

 

     2004

   2003

   Variance

   

Percentage

Change


 

Purchased Tons Sold (in millions)

     2.1      2.4      (0.3 )   (12.5 )%

Average Cost of Goods Sold and Other Charges Per Ton

   $ 36.34    $ 30.31    $ 6.03     19.9  %

 

The increase in cost of goods sold and other charges for purchased coal was primarily due to higher average cost per ton of purchased coal sold in 2004 compared to 2003. The increase in the average cost of purchased coal is primarily due to increased market prices for export and metallurgical coal. The increase in cost of goods sold and other charges was offset, in part, due to a slight decrease in volume of purchased coal sold.

 

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

 

     2004

   2003

   Variance

  

Percentage

Change


 

Produced Gas Gross Sales Volumes (in billion cubic feet)

     54.6      50.0      4.6    9.2 %

Average Cost Per Thousand cubic feet

   $ 1.93    $ 1.69    $ 0.24    14.2 %

 

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 21.2% increase in average sales price per thousand cubic feet in 2004 compared to 2003. Average cost per thousand cubic feet of gas sold also increased approximately $0.08 related to the purchase of firm transportation capacity on the Columbia Gas Transmission Corporation’s interstate pipeline because of potential curtailments on portions of the shipment capacity allocated to CONSOL Energy as a result of increased demand for pipeline. CONSOL Energy purchased firm transportation capacity on the pipeline from the May 2004 through October 2004 period to assure firm pipeline capacity of our projected production. In November 2004, CONSOL Energy entered into an extended firm transportation arrangement for use on the pipeline. This arrangement covers November 2004 through October 2006. The purchased fixed capacity on the pipeline represents approximately 35% of our projected production for the same period. These increases were offset, in part, by various reduced costs in 2004, none of which were individually material. Cost of goods sold and other charges for produced gas also increase due to increased sales volume in 2004 as a result of wells coming on-line from the ongoing drilling program.

 

In addition, in order to satisfy obligations to certain customers, we purchased from and sold to other gas suppliers, which increased our revenues and our costs. We believe this type of transaction will continue as a result of increased capacity demands on the Columbia pipeline.

 

     2004

   2003

   Variance

  

Percentage

Change


 

Purchased Gas Sales Volumes (in billion cubic feet)

     17.5    —        17.5    100.0 %

Average Cost Per Thousand Cubic Feet

   $ 6.45    —      $ 6.45    100.0 %

 

Industrial supplies’ cost of goods sold increased due to higher sales volumes and higher unit costs of goods sold.

 

Closed and idle mine costs were $72 million in 2004 compared to $62 million in 2003. The increase in cost reflects mine closing, perpetual care water treatment and reclamation liability adjustments as a result of updated engineering surveys. Survey adjustments resulted in $3 million of expense in 2004 for closed and idled locations. Closed and idle mine cost also increased approximately $10 million due to the change in calculation of workers’ compensation claims. Effective January 1, 2004, CONSOL Energy changed its method of accounting for workers’ compensation. Under the new method, the undiscounted liability is actuarially calculated based on

 

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Table of Contents

claims filed and an estimate of claims incurred but not yet reported. Additionally, the workers’ compensation liability is recorded on a discounted basis, which has been actuarially determined using various assumptions. Approximately $3 million of the increased closed and idle workers’ compensation increase is related to interest accretion. The increase in closed and idle mine cost was offset by a decrease of $6 million related to the idled Rend Lake mine. Rend Lake mine has been idle since July 2002. Closed and idle mine cost of goods sold and other charges was also impaired by approximately $3 million due to various miscellaneous transactions that occurred throughout both periods, none of which was individually material.

 

Miscellaneous cost of goods sold and other charges decreased due to the following items:

 

     2004

    2003

  

Dollar

Variance


   

Percentage

Change


 

Loveridge fire

   $ —       $ 17    $ (17 )   (100.0 )%

Mine 84 fire

     —         5      (5 )   (100.0 )%

Supply inventory write-downs

     —         5      (5 )   (100.0 )%

Other post employee benefit curtailment gain

     (3 )     —        (3 )   (100.0 )%

Cardinal River severance and pension cost

     —         2      (2 )   (100.0 )%

Buckeye landfill superfund site liability transfer

     (1 )     —        (1 )   (100.0 )%

Litigation settlements and Contingencies

     4       17      (13 )   (76.5 )%

Incentive compensation

     25       —        25     100.0 %

Sales contract buy outs

     9       1      8     800.0 %

Miscellaneous transactions

     50       55      (5 )   (9.1 )%
    


 

  


     

Total Miscellaneous Cost of Goods Sold and Other Charges

   $ 84     $ 102    $ (18 )   (17.6 )%
    


 

  


     

 

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 cost of goods sold and other charges related to extinguishing the fire was approximately $17 million and other expenses related to the fire were approximately $3 million, net of expected insurance recovery. 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 delayed this installation until March of 2004.

 

In January 2003, Mine 84 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 were estimated to cost approximately $7 million, net of expected insurance recovery, of which $5 million was attributable to cost of goods sold and other related charges and $2 million to other expenses. Longwall coal production, which accounts for the majority of coal normally produced at the mine resumed on February 10, 2003.

 

Supply inventory write-downs reflect adjustments made in 2003 to supply inventories that are unique to the equipment used at Dilworth and Rend Lake mines where the mining activities have ceased.

 

Due to the restructuring that occurred in December 2003, a curtailment gain related to the other post employment benefit plan of approximately $3 million was recognized in 2004. Due to CONSOL Energy’s measurement date being September 30, the gain was not recognized until the quarter ended March 31, 2004.

 

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Table of Contents

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. Accordingly, in 2003, CONSOL Energy recognized the cost estimate of these plans.

 

In April 2004, CONSOL Energy entered into an Environmental Liability Transfer and Indemnity Agreement that transferred our liability related to the Buckeye Landfill Superfund Site to another party. In 1991 CONSOL Energy was named a potentially responsible party related to the Buckeye Landfill Superfund Site and accordingly recognized our estimated liability for remediation of this site. The Transfer and Indemnity transaction resulted in the reversal of the remaining liability and the recognition of approximately $1 million of income.

 

Litigation settlements and contingencies decreased due to various contingent loss accruals related to asbestos, waste management and various other contingencies in both periods, none of which are individually material.

 

Incentive compensation expense increased in 2004 compared to 2003 due mainly to the level of earnings achieved in 2004 compared to projected 2004 annual results. The incentive compensation package is designed to increase compensation to eligible employees when CONSOL Energy reaches predetermined earnings targets and the employees reach predetermined performance targets. There was no incentive compensation expense in 2003 due to CONSOL Energy not achieving predetermined earnings targets.

 

In 2004, agreements were made with several customers in order to release tons committed under lower priced contracts for sale to other customers at higher pricing.

 

Cost of goods sold and other charges also decreased $5 million due to various miscellaneous transactions which occurred throughout both periods, none of which was 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.

 

     2004

   2003

  

Dollar

Variance


   

Percentage

Change


 

Freight expense

   $ 110    $ 115    $ (5 )   (4.3 )%

 

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

 

     2004

   2003

  

Dollar

Variance


   

Percentage

Change


 

Wages and salaries

   $ 25    $ 29    $ (4 )   (13.8 )%

Other post employment and pension costs

     8      11      (3 )   (27.3 )%

Professional consulting and other purchased services

     14      15      (1 )   (6.7 )%

Commissions

     7      5      2     40.0  %

Insurance

     3      2      1     50.0  %

Other

     16      16      —       —    
    

  

  


 

Total Selling, General And Administrative

   $ 73    $ 78    $ (5 )   (6.4 )%
    

  

  


 

 

Wages and salaries for selling, general and administrative have decreased primarily due to the December 2003 reduction in workforce program. The reduction program was primarily focused on reducing the number of positions in the selling, general and administrative areas to better align with CONSOL Energy’s current business strategy. The program reduced approximately 100 positions. The decreases in expense as a result of these reductions were offset, in part, by the completion of the integrated information technology system provided by

 

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Table of Contents

SAP AG in August 2003. Prior to the completion, wages and salaries for dedicated staff were capitalized as a component of the cost of the implementation project and are being amortized over seven years. The wages capitalized for 2003 were approximately $2 million.

 

Costs related to other post employment benefits in 2004 have decreased from 2003 due to the recognition of the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 in 2004.

 

Professional consulting and other purchased services has decreased in 2004 primarily due to lower software support services, offset, in part, by professional and consulting services provided in relation to reviewing employee benefit plans and compensation packages provided by CONSOL Energy.

 

Costs for coal commissions increased due to entering into an additional sales agreement in 2004 that requires commissions to be paid.

 

Insurance costs increased primarily due to the cost of director and officer insurance costs incurred in 2004. For a portion of 2003, CONSOL Energy directors and officers were previously insured under the RWE AG general liability policy.

 

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

 

     2004

   2003

  

Dollar

Variance


  

Percentage

Change


 

Coal

   $ 233    $ 196    $ 37    18.9 %

Gas

                           

Production

     23      23      —      —    

Gathering

     10      10      —      —    
    

  

  

      

Total Gas

     33      33      —      —    

Other

     14      13      1    7.7 %
    

  

  

      

Total Depreciation, Depletion and Amortization

   $ 280    $ 242    $ 38    15.7 %
    

  

  

      

 

The increase in coal depreciation, depletion and amortization was primarily attributable to the acceleration of approximately $32 million of depreciation for equipment and facilities at the Rend Lake and other idle mines. CONSOL Energy’s management reviewed the condition of the assets at these idle locations and determined no plan of use for these items, and therefore abandoned the facilities. These facilities have existing coal reserves that may be accessed from other locations or through new facilities.

 

Gas depreciation, depletion and amortization was consistent in both 2004 and 2003. Production assets are depreciated using the units of production method. Units of production depreciation was based on higher gas volumes, offset by a lower rate due to increased reserve figures at January 1, 2004 compared to January 1, 2003. Gathering assets are depreciated using the straight-line method and their depreciation did not change in the period to period comparison.

 

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 complete in August 2003.

 

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Interest expense has decreased primarily due to the following items:

 

     2004

    2003

   

Dollar

Variance


   

Percentage

Change


 

Revolving Credit Facility and Commercial Paper

   $ 4     $ 2       2     100.0  %

Long-term Debt

     32       34       (2 )   (5.9 )%

Other

     (5 )     (2 )     (3 )   (150.0 )%