Amendment No. 2 to Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K/A

Amendment No. 2

 


 

x   Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

 

For the fiscal year ended December 31, 2002; or

 

¨   Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the transition period from             

 

Commission file number: 001-14901

 


 

CONSOL ENERGY INC.

(Exact name of registrant as specified in its charter)

 


 

Delaware   51-0337383
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

 

Consol Plaza

1800 Washington Road

Pittsburgh, Pennsylvania 15241

(Address of principal executive offices including zip code)

 

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

 

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

 

Name of exchange on which registered


 

Title of each Class


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

 

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

 


 

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

 

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

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 125-2)    Yes  x    No  ¨

 

The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 28, 2002, 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 $440,597,224.

 

The number of shares outstanding of the registrant’s common stock as of March 12, 2003 is 78,749,504 shares.

 

Documents Incorporated by Reference:

 

Portions of the Company’s Proxy Statement for the Annual Meeting of Shareholders held on April 30, 2003, are incorporated by reference in Items 10, 11 and 12 of Part III

 



TABLE OF CONTENTS

 

          Page

     PART I     

Item 1.

   Business.    1

Item 2.

   Properties.    31

Item 3.

   Legal Proceedings.    31

Item 4.

   Submission of Matters to a Vote of Security Holders.    31
     PART II     

Item 5.

   Market for Registrant’s Common Equity and Related Stockholder Matters.    31

Item 6.

   Selected Financial Data.    34

Item 7.

   Management’s Discussion and Analysis of Results of Operations and Financial Condition.    38

Item 7A.

   Quantitative and Qualitative Disclosures About Market Risk.    66

Item 8.

   Financial Statements and Supplementary Data.    69

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosures.    122
     PART III     

Item 10.

   Directors and Executive Officers of the Registrant.    123

Item 11.

   Executive Compensation.    123

Item 12.

   Security Ownership of Certain Beneficial Owners and Management.    124

Item 13.

   Certain Relationships and Related Transactions.    124

Item 14.

   Controls and Procedures    124
     PART IV     

Item 15.

   Exhibits, Financial Statement Schedules and Reports on Form 8-K.    125

SIGNATURES

   128

 

i


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 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:

 

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

 

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

 

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

 

    overcapacity in the coal or gas industry impairing our profitability;

 

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

 

    reliance on major customers;

 

    the credit worthiness of our customer base declining;

 

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

 

    disputes with customers concerning contracts resulting in litigation;

 

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

 

    uncertainties in estimating our economically recoverable coal and gas reserves;

 

    risks in exploring for and producing gas;

 

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

 

    the effects of government regulation;

 

    obtaining governmental permits and approvals for our operations;

 

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

 

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

 

    results of litigation;

 

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

 

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

 

ii


    new legislation resulting in restrictions on coal use;

 

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

 

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

 

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

 

    the outcome of various asbestos litigation cases; and

 

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

 

iii


PART I

 

Item 1. Business.

 

CONSOL ENERGY’S HISTORY

 

CONSOL Energy Inc. (“CONSOL Energy” or the “Company”) is a multi-fuel energy producer and energy services provider which primarily serves the electric power generation industry in the United States. That industry generates two-thirds of its output by burning coal or gas, the two fuels CONSOL Energy produces. As of December 31, 2002, CONSOL Energy produced high-Btu bituminous coal from 22 mining complexes in the United States, Canada and Australia. Bituminous coal is the most common type of coal and has a moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btu per pound. Btu is a measure of energy required to raise the temperature of one pound of water by one degree Fahrenheit. Our coal generally has a high Btu content which creates more energy per unit when burned than coals with lesser Btu content. As a result, coals with greater Btu content can be more efficient to use. CONSOL Energy also produces pipeline-quality coalbed methane gas primarily from our coal properties in Virginia. CONSOL Energy believes that the use of coal and gas to generate electricity will grow as demand for power increases. For the twelve months ended December 31, 2002, our coal operations accounted for 88% of our revenues, our gas operations accounted for 7% of our revenues and our other operations accounted for 5% of our revenues.

 

Historically, CONSOL Energy ranks among the largest coal producers in the United States based upon total production, revenue, net income and operating cash flow. Our total production, including our portion of production from equity affiliates for the twelve months ended December 31, 2002, was 66 million tons. Our United States production of 63 million tons of coal in the twelve months ended December 31, 2002, accounted for approximately 6% of the total tons produced in the United States and 13% of the total tons produced east of the Mississippi River during that year. CONSOL Energy is one of the premier coal producers in the United States by several measures:

 

    CONSOL Energy mines more high-Btu bituminous coal than any other United States producer;

 

    CONSOL Energy is the largest coal producer, in terms of tons produced, east of the Mississippi River;

 

    CONSOL Energy exports more coal from the United States than any other coal producer or trading company;

 

    CONSOL Energy has the second largest amount of recoverable coal reserves among United States coal producers; and

 

    CONSOL Energy is the largest United States producer of coal from underground mines.

 

CONSOL Energy also operates a large coalbed methane gas company based on both its proved reserves and its current daily production. Our industry position is highlighted by several measures:

 

    We possess a large coalbed methane reserve base with 1.1 trillion cubic feet of proved reserves of gas;

 

    We currently have 134 million cubic feet of average daily coalbed methane gas production;

 

    CONSOL Energy operates more than 1,300 wells connected by approximately 740 miles of gathering lines and associated infrastructure; and

 

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

 

CONSOL Energy was organized as a Delaware corporation in 1991 and is currently a holding company for 63 direct and indirect wholly owned subsidiaries, principally engaged in the mining and sale of bituminous coal and the production and sale of coalbed methane gas.

 

1


RECENT EVENTS

 

In July 2003, Standard and Poor’s lowered its rating of CONSOL Energy’s long-term debt to BB+. Standard and Poor’s defines an obligation rated ‘BB’ (5th lowest out of 10 rating categories) as less vulnerable to nonpayment than other speculative issues. However, it faces major ongoing uncertainties or exposure to adverse business, financial or economic conditions, which could lead to the obligor’s inadequate capacity to meet its financial commitment on the obligation. The plus sign shows relative standing within the rating category.

 

Also, in July 2003, Moody’s Investor Service placed CONSOL Energy under review for possible downgrade. In August 2002, Moody’s Investor Service lowered the senior unsecured debt ratings of CONSOL Energy from Baa1 to Baa2 (9th lowest out of 21 rating categories). Moody’s Investor Service also changed our rating outlook from stable to negative. Bonds which are rated ‘Baa’ are considered as medium-grade obligations (i.e., they are neither highly protected nor poorly secured). The rating means that interest payments and principal security appear adequate for the present but certain protective elements may be lacking or may be characteristically unreliable over any great length of time. Such bonds lack outstanding investment characteristics and in fact have speculative characteristics as well. The modifier 2 indicates that the obligation ranks in the mid-range of its generic rating category.

 

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

 

In February 2003, we sold our Canadian coal assets and port facilities to Fording Inc. for a note and cash. The note was exchanged for 3.2 million units in the Fording Canadian Coal Trust, a newly organized publicly traded trust which acquired the assets of Fording Inc. We subsequently sold the units. CONSOL Energy received total proceeds of $71.7 million.

 

In February 2003, our 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 extinguishing the fire is estimated to be approximately $5 million, net of insurance recovery. The Loveridge Mine was idle during 2002. In late December 2002, the mine began 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 will delay this installation.

 

In January 2003, an explosion occurred at an airshaft construction site at the McElroy Mine resulting in the deaths of three construction workers and the injury of three other construction workers. The workers were employees of the construction company installing the shaft. The airshaft is located in an area ahead of mining activity. The explosion did not affect the normal production schedule of the mine. We do not believe that this event will have a material adverse effect on our financial condition.

 

In January 2003, Mine 84, near Washington, Pennsylvania experienced a fire along several hundred feet of the conveyor belt entry servicing the longwall section of the mine. The fire was extinguished approximately two weeks later. On January 20, 2003, the mine resumed production on a limited basis with continuous mining machines, while repairs continued on the belt entry. The fire caused damage to the roof support system, the conveyor belt and the steel framework on which the belt travels. Repairs took several weeks to complete and are estimated to cost approximately $5 million, net of insurance recovery. Longwall coal production, which accounts for the majority of coal normally produced at the mine, was suspended while repairs were made. Lost coal production is estimated to be approximately 650 thousand tons. Longwall production resumed in February 2003.

 

In January 2003, we announced that we had entered into a 17-year, 76.5 million-ton coal supply agreement with FirstEnergy Generation Corp., a subsidiary of FirstEnergy Corp. The agreement provides for annual shipments of 4.5 million tons to FirstEnergy primarily from our McElroy Mine. The agreement includes a price re-opener provision every three years, beginning in 2005. If CONSOL Energy and FirstEnergy do not agree on price at that time, the contract can be terminated by either party.

 

2


The new McElroy Mine preparation plant was put into service in September 2002. Capital expenditures of approximately $57 million have been incurred to date. The plant was designed to improve coal quality from the McElroy Mine by increasing the Btu content of the final product. The plant is part of a larger expansion of the McElroy Mine. We expect the expansion of the mine to be completed in mid 2004, and future capital expenditures are expected to be $104 million. The total expansion project will increase capacity at the McElroy Mine from about 7 million tons per year to about 11 million tons per year.

 

CONSOL Energy continues to convert to a new integrated information technology system provided by SAP AG to support business processes. The new technology is expected to provide cost-effective strategic software alternatives to meet future core business needs. The system will continue to be implemented in stages throughout 2003 at an estimated total cost of $53 million, $32 million of which has already been incurred.

 

INDUSTRY SEGMENTS

 

CONSOL Energy has two reportable business segments: Coal and Gas. The principal business of the Coal segment is mining, preparation and marketing of steam coal, sold primarily to electric utilities, and metallurgical coal, sold to steel and coke producers. The principal business of the Gas segment is to produce pipeline quality methane gas for sale primarily to gas wholesalers. Financial information concerning industry segments, as defined by generally accepted accounting principles, for the twelve months ended December 31, 2002, the six months ended December 31, 2001, and the fiscal years ended June 30, 2001 and 2000 is included in Note 27 of Notes to Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K, as amended.

 

Coal Operations

 

Mining Complexes

 

At December 31, 2002, CONSOL Energy had 22 mining complexes located in the United States, Canada and Australia, including a 50% interest in the Cardinal River and the Line Creek mines located in Canada and a 50% interest in the Glennies Creek mine located in Australia.

 

3


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

 

LOGO

 

The following table provides the location of each of CONSOL Energy’s mining complexes at December 31, 2002 and 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.

 

4


CONSOL ENERGY MINING COMPLEXES

 

Average Quality and Reserves as of December 31, 2002

 

Mine/Reserve


   Location

   Reserve Class

   Coal Seam

   Average
Seam
Thickness
(feet)


   Reserves (12/31/02) (1)

   Average Coal Quality (As—Received) (2)

   Reserves
(000 Tons)
12/31/2001


               Owned
(%)


    Leased
(%)


    Tons
(000)


   Moisture
(%)


   Sulfur
(%)


   Heat
Value
(Btu/lb)


  
ASSIGNED—OPERATING

Northern Appalachia

                                                        

Enlow Fork

   Enon, PA    Assigned    Pittsburgh    4.94    60 %   40 %   68,215    6.0    1.63    13,267    77,759
          Accessible    Pittsburgh    5.40    81 %   19 %   165,484    6.0    1.92    13,219    169,932

Bailey

   Enon, PA    Assigned    Pittsburgh    5.64    0 %   100 %   93,115    6.0    2.00    13,223    59,748
          Accessible    Pittsburgh    5.79    0 %   100 %   74,591    6.0    1.90    13,272    111,436

Mine 84

   Eighty Four, PA    Assigned    Pittsburgh    5.61    64 %   36 %   53,294    6.0    1.49    13,394    57,289
          Accessible    Pittsburgh    5.38    88 %   12 %   58,516    6.0    1.94    13,324    58,516

McElroy

   Glen Easton, WV    Assigned    Pittsburgh    5.83    100 %   0 %   176,959    5.7    3.03    13,166    181,599

Shoemaker

   Moundsville, WV    Assigned    Pittsburgh    5.54    96 %   4 %   70,008    7.3    3.40    12,864    73,367
          Accessible    Pittsburgh    5.55    100 %   0 %   15,636    7.3    2.96    12,930    15,636

Loveridge

   Fairview, WV    Assigned    Pittsburgh    7.91    100 %   0 %   13,322    5.4    2.27    13,215    13,322
          Accessible    Pittsburgh    7.39    100 %   0 %   107,033    5.5    2.81    13,347    107.033

Robinson Run

   Shinnston, WV    Assigned    Pittsburgh    7.16    74 %   26 %   33,950    6.0    3.16    13,278    38,795
          Accessible    Pittsburgh    6.90    32 %   68 %   125,780    6.7    3.19    13,158    125,780

Blacksville 2

   Wana, WV    Assigned    Pittsburgh    6.65    100 %   0 %   39,965    6.0    2.53    13,315    44,782
          Accessible    Pittsburgh    6.83    98 %   2 %   120,262    6.0    2.44    13,304    120,262

Mahoning Valley

   Cadiz, OH    Assigned    Pittsburgh    4.60    100 %   0 %   1,374    6.0    2.14    11,656    162

Humphrey

   Maidsville, WV       Pittsburgh    —      0 %   0 %   0    —      —      —      4,174

Dilworth

   Rices Landing, PA       Pittsburgh    —      0 %   0 %   0    —      —      —      3,793

Windsor

   West Liberty, WV       Pittsburgh    —      0 %   0 %   0    —      —      —      1,265

Meigs

   Langsville, Ohio       Clarion    —      0 %   0 %   0    —      —      —      400

Central Appalachia

                                                        

Buchanan

   Mavisdale, VA    Assigned    Pocahontas 3    6.25    2 %   98 %   42,467    6.3    0.73    14,008    46,530
          Accessible    Pocahontas 3    4.89    22 %   78 %   94,490    6.3    0.70    14,060    94,490

VP-3

   Vansant, VA    Assigned    Pocahontas 3    4.60    0 %   100 %   7,890    6.6    0.65    14,183    7,890

VP-8

   Rowe, VA    Assigned    Pocahontas 3    6.08    1 %   99 %   6,467    9.0    0.74    13,562    8,642

Mill Creek Complex

   Deane, KY    Assigned    Multiple    3.2-4.5    96 %   4 %   8,534    6.5    1.41    13,305    11,530
          Accessible    Multiple    3.2-4.5    93 %   7 %   17,690    6.5    1.55    13,305    17,690

Jones Fork Complex

   Mousie, KY    Assigned    Multiple    3.0-4.8    56 %   44 %   15,717    7.0    1.01    12,698    18,035
          Accessible    Multiple    3.0-4.8    41 %   59 %   26,681    7.2    1.05    12,426    26,681

Amonate Complex

   Amonate, VA    Assigned    Multiple    3.0-4.0    59 %   41 %   7,756    6.8    0.65    13,114    8,118

Elk Creek Complex

   Emmett, WV    Assigned    Multiple    3.0-5.2    50 %   50 %   10,836    5.8    0.74    10,836    10,836

Illinois Basin

                                                        

Rend Lake

   Sesser, IL    Assigned    Illinois 6    8.00    12 %   88 %   21,348    11.8    0.90    12,117    21,543
          Accessible    Illinois 6    5.99    87 %   13 %   33,705    11.8    1.47    12,082    34,976

 

5


Mine/Reserve


   Location

   Reserve Class

   Coal Seam

   Average
Seam
Thickness
(feet)


   Reserves (12/31/02) (1)

   Average Coal Quality (As—Received) (2)

  

Reserves

(000 Tons)

12/31/2001


               Owned
(%)


    Leased
(%)


   

Tons

(000)


   Moisture
(%)


   Sulfur
(%)


  

Heat Value

(Btu/lb)


  

Ohio 11

   Morganfield, KY    Assigned    Kentucky 11    4.46    0 %   100 %   8,310    11.6    2.77    11,934    8,310
          Accessible    Kentucky 11    4.44    0 %   100 %   2,198    11.5    2.88    11,878    2,198

Western U.S.

                                                        

Emery

   Emery Co., UT    Assigned    Ferron I    7.50    80 %   20 %   21,712    7.0    0.73    11,803    14,600`
          Accessible    Ferron A    8.82    47 %   53 %   12,303    7.0    0.93    11,683    13,952

Cardinal River

   Hinton, AL    Assigned    Jewell    N/A    0 %   100 %   691    8.3    0.34    12,838    884

Line Creek

   Sparwood, BC    Assigned    Multiple    N/A    0 %   100 %   30,742    8.1    0.38    12,827    32,415

Australia (New South Wales)

                                                        

Glennies Creek

   Hunter Valley, NSW    Assigned    Middle Liddel    7.68    0 %   100 %   10,205    7.0    0.45    12,778    10,337

Total Assigned—Operating

                                   1,597,246                   1,654,707

(1)   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.

 

(2)   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.

 

 

6


Excluded from the table above are approximately 181 million tons of reserves that are assigned to projects that have not produced coal in the last two years. These assigned reserves are in the Northern Appalachia (Pennsylvania, Ohio and northern West Virginia) and Central Appalachia (Virginia, southern West Virginia and Eastern Kentucky) regions. These reserves are approximately 87% owned and 13% leased. Average quality on an “as-received” basis range from 5.8% to 7.0% moisture content, 0.50% to 4.05% sulfur content and 12,393 to 13,644 heat value (British thermal units per pound).

 

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

 

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

 

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

 

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

 

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

 

Coal Reserves

 

CONSOL Energy had an estimated 4.3 billion tons of proven and probable reserves. Reserves are the portion of the proven and probable tonnage that meet CONSOL Energy’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels.

 

Proven reserves are reserves for which:

 

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

 

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

 

Consol Energy’s calculations of proven reserves generally do not rely on isolated points of observation. Small pods of measured reserves are not considered; continuity of observation points over a large area is necessary for proven status. Our estimates for proven reserves have the highest degree of geologic assurance. Estimates of rank, quality and quantity for these reserves have been computed from points of observation which are equal to or less than one half mile apart, except for our properties within the Pittsburgh 8 seam for which points of observation are 3,000 feet or less because of the well known continuity of that seam. The sites for measuring thickness of proven reserves are

 

7


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.

 

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.

 

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).

 

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

 

CONSOL Energy’s reserves are located in northern Appalachia (52%), central Appalachia (11%), the midwestern United States (21%), the western United States (11%), and in western Canada and Australia (5%) at December 31, 2002.

 

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

 

8


CONSOL Energy—UNASSIGNED Coal Reserves as of 12/31/02

 

     Reserves 12/31/02 (1)

   Range of Average Product Quality (As—Received) (2)

   Reserves
(000 Tons)
12/31/2001


Coal Producing Region


   Owned
(%)


    Leased
(%)


   

Tons

(000)


   Moisture
(%)


  

Sulfur

(%)


  

Heat Value

(Btu/lb)


  

Northern Appalachia (Pennsylvania, Ohio,

Northern West Virginia)

   92 %   8 %   896,042    4.5 –8.5      0.71  –  3.70    10,362 –13,514    896,759

Central Appalachia (Virginia, Southern West Virginia,

Eastern Kentucky)

   55 %   45 %   175,968    6.3 – 9.0      0.47  –  0.91    11,888 –14,024    173,230

Illinois Basin (Illinois, Western Kentucky,

Indiana)

   33 %   67 %   825,444    11.3 –12.1    0.76  –  3.18    10,657 –12,101    853,300

Western U.S. (Montana, Wyoming, Utah)

   58 %   42 %   439,372    24.3 –28.0    0.19  –  0.45    8,563 – 9,330      445,752

Western Canada (Alberta)

   2 %   98 %   159,975    8.0 – 8.7      0.23  –  0.54    11,194 –13,009    159,975

Total

   58 %   42 %   2,496,801                   2,529,016

1)   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 it receives 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.

 

2)   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.

 

9


The following table summarizes our proven and probable reserves as of December 31, 2002 by region, 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.

 

10


CONSOL ENERGY PROVEN AND PROBABLE COAL RESERVES

BY PRODUCING REGION AND PRODUCT (000 TONS) AS OF DECEMBER 31, 2002

 

    £ 1.20 lbs

  > 1.20 < 2.50 lbs

  > 2.50 lbs

  Total

   Percentage
By Region


 
    S02/MMBtu

  S02/MMBtu

  S02/MMBtu

    

By Region


  Low Btu

  Med Btu

  High Btu

  Low Btu

  Med Btu

  High Btu

  Low Btu

  Med Btu

  High Btu

    

Northern Appalachia:

                                              

Metallurgical:

                                              

High Vol A Bituminous

  —     —     —     —     —     187,205   —     —     —     187,205    4.4 %

Steam:

                                              

High Vol A Bituminous

  —     49,359   —     —     10,038   121,509   48,231   119,283   1,699,121   2,047,541    47.9 %

Low Vol Bituminous

  —     —     —     —     —     15,911   —     —     —     15,911    0.3 %
   
 
 
 
 
 
 
 
 
 
  

Region Total

  —     49,359   —     —     10,038   324,625   48,231   119,283   1,699,121   2,250,657    52.6 %

Central Appalachia:

                                              

Metallurgical:

                                              

High Vol A Bituminous

  7,325   —     18,645   —     —     2,103   —     —     —     28,073    0.6 %

Med Vol Bituminous

  —     3,456   81,381   —     2,417   6,129   —     —     —     93,383    2.2 %

Low Vol Bituminous

  —     —     158,968   —     —     8,174   —     —     —     167,142    3.9 %

Steam:

                                              

High Vol A Bituminous

  26,967   24,724   1,306   27,341   32,266   42,354   —     —     15,163   170,121    4.0 %
   
 
 
 
 
 
 
 
 
 
  

Region Total

  34,292   28,180   260,300   27,341   34,683   58,760   —     —     15,163   458,719    10.7 %

Midwest—Illinois Basin:

                                              

Steam:

                                              

High Vol B Bituminous

  —     —     —     —     68,535   55,053   56,963   425,894   34,437   640,882    15.0 %

High Vol C Bituminous

  —     —     —     —     158,136   —     91,987   —     —     250,123    5.9 %
   
 
 
 
 
 
 
 
 
 
  

Region Total

  —     —     —     —     226,671   55,053   148,950   425,894   34,437   891,005    20.9 %

Northern Powder River Basin:

                                              

Steam:

                                              

Subbituminous B

  —     —     248,609   —     —     4,126   —     —     —     252,735    5.9 %

Subbituminous C

  —     186,637   —     —     —     —     —     —     —     186,637    4.4 %
   
 
 
 
 
 
 
 
 
 
  

Region Total

  —     186,637   248,609   —     —     4,126   —     —     —     439,372    10.3 %

Utah—Emery Field:

                                              

High Vol B Bituminous

  —     —     —     —     34,015   —     —     —     —     34,015    0.8 %
   
 
 
 
 
 
 
 
 
 
  

Region Total

  —     —     —     —     34,015   —     —     —     —     34,015    0.8 %

Western Canada:

                                              

Metallurgical:

                                              

Med Vol Bituminous

  102,407   31,684   26,575   —     —     —     —     —     —     160,666    3.7 %

Low Vol Bituminous

  —     28,588   —     —     —     —     —     —     —     28,588    0.7 %

Steam:

                                              

Low Vol Bituminous

  2,154   —     —     —     —     —     —     —     —     2,154    0.1 %
   
 
 
 
 
 
 
 
 
 
  

Region Total

  104,561   60,272   26,575   —     —     —     —     —     —     191,408    4.5 %

Hunter Valley, Australia

                                              

Metallurgical:

                                              

High Vol A Bituminous

  —     10,205   —     —     —     —     —     —     —     10,205    0.2 %
   
 
 
 
 
 
 
 
 
 
  

Region Total

  —     10,205   —     —     —     —     —     —     —     10,205    0.2 %
   
 
 
 
 
 
 
 
 
 
  

Total Company

  138,853   334,653   535,484   27,341   305,407   442,564   197,181   545,177   1,748,721   4,275,381    100.0 %
   
 
 
 
 
 
 
 
 
 
  

 

11


     £ 1.20 lbs

    > 1.20 < 2.50 lbs

    > 2.50 lbs

    Total

    Percentage
By Region


    

S02/MMBtu


   

S02/MMBtu


   

S02/MMBtu


     

By Region


   Low Btu

    Med Btu

    High Btu

    Low Btu

    Med Btu

    High Btu

    Low Btu

    Med Btu

    High Btu

     

Percent of Total

   3.3 %   7.8 %   12.5 %   0.6 %   7.1 %   10.4 %   4.6 %   12.8 %   40.9 %   100.0 %    
    

 

 

 

 

 

 

 

 

 

 

 

CONSOL ENERGY PROVEN AND PROBABLE COAL RESERVES

BY PRODUCT (000 TONS) AS OF DECEMBER 31, 2002

 

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

 

     £ 1.20 lbs

    > 1.20 - < 2.50 lbs

    ³ 2.50 lbs

     Total

    

Percentage

By Product


 
     S02/MMBtu

    S02/MMBtu

    S02/MMBtu

       

By Product


   Low
Btu


    Med
Btu


    High
Btu


    Low Btu

    Med
Btu


    High
Btu


    Low
Btu


     Med
Btu


     High Btu

       

Metallurgical:

                                                                      

High Vol A Bituminous

   7,325     10,205     18,645     —       —       189,308     —        —        —        225,483      5.3 %

Med Vol Bituminous

   102,407     35,140     107,956     —       2,417     6,129     —        —        —        254,049      5.9 %

Low Vol Bituminous

   —       28,588     158,968     —       —       8,174     —        —        —        195,730      4.6 %
    

 

 

 

 

 

 

  

  

  

  

Total Metallurgical

   109,732     73,933     285,569     —       2,417     203,611     —        —        —        675,262      15.8 %

Steam:

                                                                      

High Vol A Bituminous

   26,967     74,083     1,306     27,341     42,304     163,863     48,231      119,283      1,714,284      2,217,662      51.8 %

High Vol B Bituminous

   —       —       —       —       102,550     55,053     56,963      425,894      34,437      674,897      15.8 %

High Vol C Bituminous

   —       —       —       —       158,136     —       91,987      —        —        250,123      5.9 %

Low Vol Bituminous

   2,154     —       —       —       —       15,911     —        —        —        18,065      0.4 %

Subbituminous B

   —       —       248,609     —       —       4,126     —        —        —        252,735      5.9 %

Subbituminous C

   —       186,637     —       —       —       —       —        —        —        186,637      4.4 %
    

 

 

 

 

 

 

  

  

  

  

Total Steam

   29,121     260,720     249,915     27,341     302,990     238,953     197,181      545,177      1,748,721      3,600,119      84.2 %
    

 

 

 

 

 

 

  

  

  

  

Total

   138,853     334,653     535,484     27,341     305,407     442,564     197,181      545,177      1,748,721      4,275,381      100.0 %
    

 

 

 

 

 

 

  

  

  

  

Percent of Total

   3.3 %   7.8 %   12.5 %   0.6 %   7.1 %   10.4 %   4.6 %    12.8 %    40.9 %    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, Canada and Australia

   < 12,500    12,500 – 13,000    > 13,000

Midwest

   < 11,600    11,600 – 12,000    > 12,000

Northern Powder River Basin

   < 8,400    8,400 – 8,800    > 8,800

Colorado and Utah

   < 11,000    11,000 – 12,000    > 12,000

 

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

 

12


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, 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. None of our coal reserves have been reviewed by independent experts.

 

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. 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 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 lb of sulphur dioxide per million British thermal units of fuel consumed. 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.

 

Production

 

In the twelve months ended December 31, 2002, 92% of CONSOL Energy’s production came from underground mines and 8% 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, 2002, 82% 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.

 

The following table shows the production, in millions of tons, for CONSOL Energy’s mines in the twelve months ended December 31, 2002, 2001 and 2000, the location of each mine, the type of mine, the type of equipment used at each mine and the year each mine was established or acquired by us. The table includes information for five mines, Dilworth, Humphrey, Meigs, Muskingum and Windsor, that closed during the year because of reserve depletion. In February 2003, we sold our Cardinal River and Line Creek Mines in western Canada.

 

Mine


   Location

   Mine Type

   Mining
Equipment


   Transportation

   Tons Produced

  

Year
Established

or Acquired


               2002

   2001

   2000

  
                         (in millions)     

Northern Appalachia

                                       

Enlow Fork

   Enon, Pennsylvania    U    LW/CM    R R/B    9.6    10.3    9.5    1990

Bailey

   Enon, Pennsylvania    U    LW/CM    R R/B    9.7    10.3    9.9    1984

McElroy

   Glen Easton, West Virginia    U    LW/CM    B    4.7    6.6    6.8    1968

Robinson Run

   Shinnston, West Virginia    U    LW/CM    R CB    5.0    4.9    6.0    1966

Mine No. 84

   Eighty Four, Pennsylvania    U    LW/CM    R R/B T    4.0    1.4    4.2    1998

Blacksville 2

   Wana, West Virginia    U    LW/CM    R R/B T    4.8    5.0    5.2    1970

Dilworth (2)

   Rices Landing, Pennsylvania    U    LW/CM    B    3.6    4.7    4.8    1984

Shoemaker

   Moundsville, West Virginia    U    LW/CM    B    3.4    4.1    3.6    1966

Loveridge (3)

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

Humphrey (2)

   Maidsville, West Virginia    U    CM    R    0.5    0.7    0.7    1956

Mahoning Valley

   Cadiz, Ohio    S    S/L    R T    0.3    0.5    0.4    1974

Meigs (2)

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

Muskingum (2)

   Cumberland, Ohio    S    D    R    —      0.5    —      2001

 

13


Mine


   Location

   Mine Type

   Mining
Equipment


   Transportation

   Tons Produced

   Year
Established
or Acquired


               2002

   2001

   2000

  

Windsor (2)

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

Central Appalachia

                                       

Buchanan

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

VP-3 (3)

   Vansant, Virginia    U    LW/CM    R    —      —      —      1993

VP-8

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

Mill Creek (1)

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

Jones Fork (1)

   Mousie, Kentucky    U/S    CM    R T    4.0    4.9    3.1    1992

Amonate (1)

   Amonate, Virginia    U    CM    R    0.5    0.5    0.5    1925

Illinois Basin

                                       

Rend Lake (3)

   Sesser, Illinois    U    LW/CM    R T    1.7    2.0    2.7    1986

Ohio No. 11 (3)

   Morganfield, Kentucky    U    CM    R    —      —      —      1993

Western U.S.

                                       

Emery (4)

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

Western Canada

                                       

Cardinal River (5)

   Hinton, Alberta, Canada    S    S/L    R    1.2    1.7    1.5    1969

Line Creek (5)

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

Australia

                                       

Glennies Creek

   Hunter Valley, New South
Wales, Australia
   U    LW/CM    R    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)   Amonate, Mill Creek and Jones Fork complexes include operations by independent mining contractors.
(2)   Production at the complex ceased during the twelve months ended December 31, 2002, due to the depletion of economically recoverable reserves.
(3)   Loveridge, VP-3, Rend Lake and Ohio No. 11 were idled for all or part of the year ended December 31, 2002 due to market conditions.
(4)   Complex was in development at December 31, 2002.
(5)   Sold in February 2003.

 

The amounts shown for tons produced for all periods presented by Cardinal River, 1.2 million tons, Line Creek, 1.7 million tons and Glennies Creek, 0.1 million tons, actually represents 50% of the production of each mine, reflecting our 50% interest in each mine at December 31, 2002.

 

14


Our sales of bituminous coal were at an average sales price per ton produced of $26.76, $25.02, $23.93 and $23.66 for the twelve month period ended December 31, 2002, the six month period ended December 31, 2001 and the twelve month periods ended June 30, 2001 and 2000, respectively.

 

Expansion projects are planned at several of our mining complexes. These projects include the expansion of McElroy Mine that is intended to increase capacity from about seven million tons per year to about 11 million tons per year. The new preparation plant at McElroy, put into service in September 2002, was the first phase of the project. The remaining expansion currently is expected to be completed in mid 2004. A project also has been approved to complete a preparation plant expansion at the shared Bailey and Enlow facility. The expansion of the preparation plant facilities will allow production at these two mines to be increased. This expansion currently is expected to be completed in late 2004. In late 2002, the Buchanan mine installed a new longwall system which currently is expected to increase productive capacity to over 4.5 million tons per year.

 

In 2001, Mine 84 encountered in the coal seam a sandstone intrusion that ran across several longwall coal panels. Because sandstone is harder than coal, mining advance rates were slowed for both longwall and continuous mining machines. In 2002, Mine 84 production continued to be lower than anticipated because of several factors including a one month idled period taken because of market conditions, mechanical problems encountered throughout the year, and adverse geological conditions experienced periodically.

 

Our Loveridge mine, which was on long-term idle status in 2002 due to market conditions, experienced a mine fire in early 2003. The fire is currently being extinguished and plans are being made to re-enter the mine to prepare for production during the first-half of 2004.

 

In July 2003, we agreed to sell the physical assets, inventory, mineral reserves and operation of the Emery Mine in Utah. The sale is subject to final due diligence and receipt of various approvals and currently is expected to close in the fourth quarter of 2003.

 

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

 

The following table sets forth, with respect to properties that we lease to other coal operators, the total annual royalty tonnage mined from our properties, the total acreage leased and the amount of income (net of related expenses) we received from royalty payments from other operators for the twelve months ended December 31, 2002, 2001 and 2000.

 

Year

  Total Royalty Tonnage

  Total Coal Acreage
Leased


  Total Royalty Income

    (in thousands)       (in thousands)

2002

  17,680   202,033   $ 7,451

2001

  18,050   182,203   $ 5,723

2000

  10,167   181,142   $ 4,300

 

Royalty tonnage 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.

 

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

 

The following table ranks the 20 largest underground mines in the United States by tons of coal produced in calendar year 2001, the latest information available at the time of filing.

 

15


MAJOR U.S. UNDERGROUND COAL MINES—2001

In millions of tons

 

Mine Name


  

Operating Company


   Production

Bailey

   CONSOL Energy    10.3

Enlow Fork

   CONSOL Energy    10.3

Twentymile

   Twentymile Coal Company    7.7

SUFCO

   Canyon Fuel Company    7.0

Galatia

   The American Coal Co.    6.8

Cumberland

   RAG Cumberland Resources Corp.    6.7

Emerald

   RAG Emerald Resources Corp.    6.7

McElroy

   CONSOL Energy    6.6

Baker

   Lodestar Energy, Inc.    6.3

Bowie

   Bowie Resources, LTD    5.4

Mountaineer

   Arch Coal, Inc.    5.3

Blacksville 2

   CONSOL Energy    5.0

Federal No. 2

   Eastern Associated Coal Corp.    5.0

West Elk

   Arch Coal Inc.    5.0

Robinson Run

   CONSOL Energy    4.9

Dilworth

   CONSOL Energy    4.7

Dotiki

   Webster County Coal LLC    4.6

Powhatan No. 6

   Ohio Valley Coal Co.    4.6

Buchanan

   CONSOL Energy    4.4

Deer Creek

   Energy West Mining Co.    4.3

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, Norfolk, Philadelphia and Pittsburgh and an overseas office in Brussels, Belgium. In addition, we sell coal through agents, brokers and unaffiliated trading companies. In the twelve months ended December 31, 2002, we sold 67 million tons of coal, including our percentage of sales in equity affiliates, 89% of which was sold in domestic markets. Our direct sales to domestic electricity generators represented 78% of our total tons sold in the twelve months ended December 31, 2002. Including equity affiliate sales, we had approximately 170 customers in the twelve months ended December 31, 2002. During the twelve months ended December 31, 2002, Allegheny Energy accounted for 15% of our total revenue and American Electric Power accounted for approximately 11% of our total revenue.

 

Coal Contracts

 

We sell coal to customers under arrangements that are the result of both bidding procedures and extensive negotiations. We sell coal for terms that range from a single shipment to multi-year agreements for millions of tons. During the twelve months ended December 31, 2002, approximately 82% 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.

 

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A few contracts have features of several contract types, such as provisions that allow for renegotiation of prices on a limited basis within a base-price-plus-escalation agreement. Such reopener 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 reopener provisions differ from contract to contract. Many contracts provide for a periodic resetting of prices if market prices fall outside negotiated parameters. Most of our existing contracts with reopener provisions adjust the contract price to market price at the time the reopener provision is triggered. Market price generally is based on recent published transactions for similar quantities and quality of coal. Reopener provisions could result in early termination of a contract or in requirements that certain volumes be purchased if the parties were to fail to agree on price and other terms that may be subject to renegotiation.

 

The following table sets forth, as of February 1, 2003, the total tons of coal CONSOL Energy is committed to deliver at predetermined prices, including prices that are adjusted as often as quarterly based upon indices which are prenegotiated, under existing contracts during calendar years 2003 through 2007.

 

    

Tons of Coal to be Delivered

(in millions of nominal tons)


     2003

   2004

   2005

   2006

   2007

Volume under existing contracts:

   52.4    32.7    13.8    6.8    4.9

 

The foregoing table does not include an aggregate of 12.1 million tons that we may be required to deliver in 2003 at predetermined prices:

 

    under tentative agreements reached by February 1, 2003, for which no binding contracts have been negotiated or executed;

 

    upon exercise of rights by customers under existing contracts to buy more coal at previously agreed prices; and

 

    under agreements which call for the price to be determined by mutual agreement of the parties.

 

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

 

Contracts also typically contain force majeure provisions allowing for the suspension of performance by the customer or us for the duration of specified events beyond the control of the affected party, including labor disputes. Some contracts may terminate upon continuance of an event of force majeure for an extended period, which 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 volume or timing of delivery within specified limits.

 

Many of our recently negotiated contracts have had shorter terms, generally no longer than three to five years. Many contracts provide the opportunity to adjust the contract prices. Contract prices may be adjusted as often as quarterly based upon indices which are prenegotiated, to reflect changing markets. One exception to this is a seventeen year, 76.5 million ton coal agreement entered into in January 2003. This agreement provides for annual shipments of 4.5 million tons to FirstEnergy Generation Corp., a subsidiary of FirstEnergy Corp., primarily from McElroy Mine. Most of the supply is expected to be used at FirstEnergy’s Bruce Mansfield Plant. The agreement includes a price re-opener provision every three years, beginning in 2005. If CONSOL Energy and FirstEnergy do not agree on price at that time, the contract can be terminated by either party.

 

Distribution

 

Coal is transported from CONSOL Energy’s mining complexes to customers by means of railroad cars, river barges, trucks, conveyor belts or a combination of these means of transportation. The Robinson Run Mine transports coal to customers by conveyor belt. The McElroy, Shoemaker, and Ohio No. 11 complexes ship coal to customers by means of river barges. Trucks are used to transport coal from the Loveridge, Mine 84, Jones Fork,

 

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Blacksville, Rend Lake, Mahoning Valley and Emery complexes. The Enlow Fork, Bailey, Mine No. 84, Robinson Run, Loveridge, Line Creek, Blacksville, Buchanan, Mill Creek, VP-3, Jones Fork, VP-8, Amonate, Elk Creek, Rend Lake and Cardinal River complexes primarily transport coal to customers by rail.

 

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

 

We own five towboats and six harbor boats and a fleet of nearly 300 barges to serve customers along the Ohio and Monongahela Rivers. The barge operation allows us to control delivery schedules and serves as temporary floating storage for coal where land storage is unavailable. Approximately 40% of the coal that we produced was shipped on the inland waterways in the twelve months ended December 31, 2002.

 

Competition

 

The United States coal industry is highly competitive, with numerous producers in all coal producing regions. CONSOL Energy competes against other large producers and hundreds of small producers in the United States and overseas. The largest producer is estimated by the 2002 National Mining Association Survey to have produced less than 18% (based on tonnage produced) of the total United States production in 2001. The U.S. Department of Energy reported 1,512 active coal mines in the United States in 2001, 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.

 

Gas Operations

 

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

 

Nearly all of our gas production currently is from operations in southwestern Virginia. In this region, we operate 1,235 wells, 708 miles of gathering lines and various compression stations. Our southwestern Virginia operations control approximately 210,000 acres of gas rights. At December 31, 2002, we reported 1.1 trillion cubic feet of proved reserves of gas, of which approximately 33.2% is developed. Our December 2002 average daily production in this region is approximately 131 million cubic feet per day.

 

We have been developing gas production in southwestern Pennsylvania and northern West Virginia by gathering gas currently being vented to the atmosphere by our mines in the area. In this region, our December 2002 average daily production was approximately 2.5 million cubic feet per day. At December 31, 2002, we reported

 

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15.8 billion cubic feet of proved reserves of gas, of which approximately 78% is developed. We expect to expand production of gas in this area by drilling additional production wells into the coal seams that we own or control.

 

We have also been developing gas production in the Tennessee area through a 50% joint venture. In this area, our 50% portion of December 2002 average daily production was approximately 0.3 thousand cubic feet per day. At December 31, 2002, our portion of proved gas reserves for this area was 0.6 billion cubic feet, all of which were developed.

 

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

 

Drilling

 

The total average daily rate of production controlled by CONSOL Energy during the twelve months ended December 31, 2002, was 129.2 million cubic feet. During the twelve months ended December 31, 2002, the six months ended December 31, 2001, and the twelve months ended June 30, 2001, and 2000, we drilled in the aggregate, 197, 141, 203, and 130 coalbed methane development wells, respectively, all of which were productive. The net number of wells for those periods were approximately 194, 141, 157, and 82 wells, respectively. Ten coalbed methane and nineteen conventional exploratory wells were being drilled and evaluated at December 31, 2002, 17 exploratory wells were being drilled at December 31, 2001, and two exploratory wells were being drilled at June 30, 2001.

 

Production

 

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

 

    

For the Twelve
Months Ended
December 31,

2002


  

For the Six
Months Ended
December 31,

2001


   For the Twelve
Months Ended
June 30,


           2001

   2000

Coalbed methane (in millions of cubic feet)

   47,164    19,885    34,004    16,235

 

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

 

Average Sales Prices and Lifting Costs

 

The following table sets forth the average sales price and the average lifting cost for all of our gas production for the periods indicated. Lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization. See Note 30 of Notes to Consolidated Financial Statements.

 

     Average Gas Sales Price, Lifting Cost, and Royalty for the

     Twelve Months
Ended
December 31,


   Six Months
Ended
December 31,


  

Twelve Months
Ended

June 30,


     2002

   2001

   2001

   2000

Average gas sales price (per million Btu)

   $ 3.22    $ 2.67    $ 5.27    $ 3.06

Average lifting cost (per million Btu)

   $ 0.36    $ 0.47    $ 0.37    $ 0.48

Average royalty (per million Btu)

   $ 0.27    $ 0.18    $ 0.54    $ 0.20

 

Productive Wells and Acreage

 

The following table sets forth, at December 31, 2002, the number of CONSOL Energy’s producing wells, developed acreage and undeveloped acreage.

 

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     Gross

   Net

Producing Wells

   1,317    1,313

Developed Acreage

   105,881    105,631

Undeveloped Acreage

   360,267    243,681

 

We drilled 197 development wells in the twelve months ended December 31, 2002, of which eight wells were in process at December 31, 2002. Nearly all of our development wells and acreage are located in southwestern Virginia. Some leases are beyond their primary term, but such leases are extended in accordance with their terms as long as certain drilling commitments are satisfied.

 

We currently plan to drill approximately 269 wells in the twelve month period ending December 31, 2003. 161 of these wells are proposed to be conventional coalbed methane wells drilled into coal seams not yet mined. 68 of the remaining wells are to be drilled into mine areas to produce gob gas, which is methane gas that has collected in abandoned areas of underground coal mines. 40 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.

 

Sales

 

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with our gas marketers, selling gas under short-term multi-month contracts generally not exceeding one year. Within the terms of the individual sales confirmations executed under the master marketing contracts, at December 31, 2002, we were obligated to deliver 44.8 billion cubic feet during the twelve month period ending December 31, 2003. Generally, we have not entered into such arrangements in the past. Reserves and production estimates are believed to be sufficient to cover these commitments. A shortfall of commitments has not been an issue historically. 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, 2002.

 

The hedging strategy and information regarding derivative instruments used are outlined in item 7A, “Qualitative and Quantitative Disclosures About Market Risk”, and in Note 25 to the audited financial statements.

 

Distribution

 

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

 

Gas Reserves

 

CONSOL Energy’s gas reserves are either owned or leased. The following table shows our estimated proven developed and proven undeveloped reserves. Reserve information is gross, and includes 100% of the reserves for Pocahontas Gas Partnership as of December 31, 2002, and December 31, 2001, and 50% of the reserves for Pocahontas Gas Partnership as of June 30, 2001, and June 30, 2000. CONSOL Energy owned a 50% interest in Pocahontas until August 2001, when CONSOL Energy acquired the remaining 50% interest. Gross reserves are

 

20


100% of gas volumes, not net of  1/8 royalty ownership. Proven developed and proven undeveloped gas reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations.

 

Proved developed and undeveloped gas reserves are defined by the Securities and Exchange Commission Rule 4.10(a) of Regulation 5-X.

 

    

GAS Reserves

(millions of cubic feet)


     As of December 31,

   As of June 30,

     2002

   2001

   2001

   2000

Estimated proven developed reserves

   374,098    413,234    261,426    178,690

Estimated proven undeveloped reserves

   729,115    762,998    519,081    568,123

Total estimated proven developed and
undeveloped reserves

   1,103,213    1,176,232    780,507    746,813

 

Discounted Future Net Cash Flows

 

The following table shows, for CONSOL Energy’s gross estimated proven developed and undeveloped reserves, its estimated future net cash flows and total standardized measure of discounted, at 10%, future net cash flows (net of income taxes). Information as of December 31, 2001, has been restated from $433,224 for future net cash flows and $218,365 for total standardized measure of discounted future net cash flows previously included in our reports due to revisions in development costs for that period.

 

    

Discounted Future Net Cash Flows

($ in thousands)


     As of December 31,

   As of June 30,

     2002

   2001

   2001

   2000

Future net cash flows

   $ 2,037,696    $ 901,343    $ 551,607    $ 1,150,826

Total standardized measure of
discounted future net cash flows

   $ 735,181    $ 345,826    $ 189,156    $ 494,581

 

Competition

 

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

 

Other

 

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

 

Terminal Services

 

More than 131 million tons of coal have been shipped through CONSOL Energy’s exporting terminal in the Port of Baltimore during the terminal’s 20 years of operation. 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. In the twelve months ended December 31, 2002, 3.8 million tons of coal were shipped through the terminal. Approximately 75% of the tonnage shipped was produced by our coal mines.

 

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

 

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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 nearly 300 barges. In the twelve months ended December 31, 2002, our river vessels transported 15.1 million tons of our coal.

 

CONSOL Energy provides dock services at Kellogg Dock, located on the Mississippi River in southern Illinois, and Alicia Dock, located on the Monongahela River in Fayette County, Pennsylvania, north of the Dilworth mine. 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.

 

Industrial Supply Services

 

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

 

Fairmont Supply provides mine supplies to CONSOL Energy’s mining operations. Approximately 53% of Fairmont Supply’s sales in the twelve months ended December 31, 2002, were made to CONSOL Energy’s mines.

 

Land Resources

 

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

 

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

 

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

 

    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.

 

Research and Development

 

We maintain a research and development department which provides technical support to coal, gas, land and administrative functions. In addition to the research and technical support work done for us, the department has engaged in a number of partnerships with federal and state government agencies, and other private companies, that provide additional funding to advance our technology agenda. Costs related to research and development are

 

22


expensed as incurred. These costs were $5.6 million for the twelve months ended December 31, 2002, $2.3 million for the six months ended December 31, 2001, and $5.3 million and $8.0 million for the twelve months ended June 30, 2001 and 2000, respectively.

 

Power Generation

 

In March 2002, we entered into a joint venture with Allegheny Energy Supply Company, LLC, an affiliate of one of our largest coal customers, to build an 88-megawatt, gas-fired electric generating facility. This facility was completed in June 2002 at a total cost of approximately $56 million, of which CONSOL Energy paid approximately $28 million, and is used for meeting peak load demands. The facility is in southwest Virginia and uses coalbed methane gas that we produce. In the twelve months ended December 31, 2002, the facility operated for a total of 34,540 megawatt hours and did not have a significant effect on earnings in 2002.

 

Employee and Labor Relations

 

At December 31, 2002, CONSOL Energy had 6,074 employees, 2,175 of whom were represented by the United Mine Workers of America and covered by the terms of the National Bituminous Coal Wage Agreement of 2002 which will expire on December 31, 2006. This agreement was negotiated with the United Mine Workers of America by the Bituminous Coal Operators’ Association on behalf of its members, which include several of CONSOL Energy’s subsidiaries.

 

Regulations

 

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

 

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

 

While it is not possible to quantify the costs of compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. CONSOL Energy made capital expenditures for environmental control facilities of approximately $1.4 million for the twelve months ended December 31, 2002, $3.5 million for the six months ended December 31, 2001, $2.9 million for the twelve months ended June 30, 2001, and $1.6 million for the twelve months ended June 30, 2000. CONSOL Energy expects to have capital expenditures of $1.8 million for 2003 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

 

23


significantly expanded the enforcement of safety and health standards of the 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 Mine Safety and Health Act of 1969 and the 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 $462 million at December 31, 2002. These obligations are partially funded.

 

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

 

The United States Department of Labor issued a final rule, effective January 19, 2001, amending the regulations implementing the federal black lung laws. The amendments give greater weight to the opinion of the claimant’s treating physician, expand the definition of black lung disease and limit the amount of medical evidence that can be submitted by claimants and respondents. The amendments also alter administrative procedures for the adjudication of claims, which, according to the Department of Labor, results in streamlined procedures that are less formal, less adversarial and easier for participants to understand. These and other changes to the black lung regulations could significantly increase our exposure to black lung benefits liabilities. Experience to date related to these changes is not sufficient to determine the impact of these changes. The National Mining Association, an industry association of which CONSOL Energy is a member, challenged the amendments in the United States District Court for the District of Columbia. On August 9, 2001, the Court issued an opinion upholding the United States Department of Labor’s rules in their entirety. The National Mining Association appealed this decision to the United States Court of Appeals. On June 14, 2002, the Court of Appeals issued a decision that, with minor exception, affirmed the rules. However, the decision left many contested issues open for interpretation. Consequently, we anticipate increased litigation over the next two to three years until the various federal District Courts have had an opportunity to rule on these issues.

 

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Workers’ Compensation

 

CONSOL Energy is required to compensate employees for work-related injuries. Our workers’ compensation liabilities, including the current portion, were $317 million at December 31, 2002. These obligations are unfunded. The amount we expensed in the twelve months ended December 31, 2002, was $61 million, while the related cash payment for this liability was $79 million. This includes a one-time payment of $22 million for West Virginia State Administration Fees which was primarily related to contractors who defaulted on contributions. In addition, 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.

 

Retiree Health Benefits Legislation

 

The Coal Industry Retiree Health Benefit Act of 1992 requires CONSOL Energy to make payments to fund the cost of health benefits for our and other coal industry retirees. Based on available information, at December 31, 2002, CONSOL Energy’s obligation is estimated at approximately $658 million. We made payments and expensed such health benefits of $35 million in the twelve months ended December 31, 2002.

 

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 Substance Control Act,

 

    the Comprehensive Environmental Response, Compensation and Liability Act, and

 

    the Resource Conservation and Recovery Act, as well as state laws of similar scope in each state in which CONSOL Energy operates.

 

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

 

25


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.

 

Through December 31, 2002, CONSOL Energy accrued for the costs of reclaiming the mine disturbance and of final mine closure, including the cost of treating mine water discharge where necessary, over the estimated recoverable tons of the property. The establishment of liability for the current disturbance and final mine closure reclamation is based upon permit requirements and requires various estimates and assumptions, principally associated with costs and production levels. Our reclamation and mine-closing liabilities, including the current portion, were $391 million at December 31, 2002. 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, 2002 was $16 million, while the related cash payment for such liability during the same period was $24 million.

 

In January 2003, CONSOL Energy will adopt Statement of Financial Accounting Standards No. 143 (SFAS 143) to account for the costs related to the closure of mines and gas wells and the reclamation of the land upon exhaustion of coal and gas reserves. This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimate asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate to the closure of mines and gas wells and the reclamation of the land upon exhaustion of coal and gas reserves. We are anticipating the effect of this change to be a gain of $5 million, net of a tax cost of $3 million. At the time of adoption, total assets, net of accumulated depreciation, will increase approximately $59 million, and total liabilities will increase approximately $51 million. The amounts recorded upon adoption are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.

 

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

 

Clear Air Act

 

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

 

The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal fueled electric power generating plants. Coal contains impurities, such as sulfur, mercury, chlorine and other regulated constituents, many of which are released into the air when coal is burned. New environmental regulations governing emissions from coal-fired electric generating plants could reduce demand for coal as a fuel source and

 

26


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

 

Other new and proposed reductions in emissions of mercury, nitrogen oxides, particulate matter or various greenhouse gases may require the installation of additional costly control technology or the implementation of other measures, including switching to other fuels. These new and proposed reductions will make it more costly to operate coal-fired plants and could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. For example, the United States Environmental Protection Agency (EPA) is requiring reduction of nitrogen oxide emissions in 22 eastern states and the District of Columbia and will require reduction of particulate matter emissions over the next several years for areas that do not meet air quality standards for fine particulates. EPA is also working on an implementation plan for the 8-hour ozone standard and this may require some customers to further reduce NOx emissions, a precursor of ozone. In addition, Congress and several states are now considering legislation to further control air emissions of multiple pollutants from electric generating facilities and other large emitters. To the extent that any new requirements affect our customers, this could adversely affect our operations and results.

 

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

 

The Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not yet been extended to coal mining operations, the EPA has announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009, which likely will require significant new investment in controls by power plant operators. These standards and future standards could have the effect of decreasing demand for coal.

 

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

 

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

 

CONSOL Energy has obtained all necessary permits under the Clean Air Act. The expiration dates of these permits range from April 21, 2004 through June 30, 2008. Permitting costs with respect to the Clean Air Act were less than $19 thousand for the twelve months ended December 31, 2002, the six months ended December 31, 2001, and the twelve months ended June 30, 2002. CONSOL Energy’s permitting costs were $0.2 million for the twelve months ended June 30, 2000.

 

Framework Convention On Global Climate Change

 

The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change which is intended to limit or capture emissions of greenhouse gases such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emissions targets

 

27


for developed nations. Although the specific emissions targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. The United States Senate is not expected to ratify the emissions targets. President Bush has stated that he does not support the Kyoto Protocol and has proposed an alternative to reduce United States omissions of greenhouses gases. If the Kyoto Protocol or other comprehensive regulations focusing on greenhouse gas emissions are implemented by the United States, it could have the effect of restricting the use of coal. Other efforts to reduce emissions of greenhouse gases and federal initiatives to encourage the use of coalbed methane gas also may affect the use of coal as an energy source.

 

Clean Water Act

 

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

 

Comprehensive Environmental Response, Compensation and Liability Act (Superfund)

 

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

 

From time to time, we have been the subject of administrative proceedings, litigation and investigations relating to environmental matters. We have been named as a potentially responsible party at Superfund sites in the past. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us. In September 1991, CONSOL Energy was named a potentially responsible party related to the Buckeye Landfill Superfund Site. The estimated total remaining remediation cost for all potentially responsible parties is approximately $15 million at December 31, 2002. CONSOL Energy’s portion of this claim is approximately 20%. CONSOL Energy has a liability for the remaining remediation costs of approximately $2.9 million at December 31, 2002. To date, CONSOL Energy has paid $2.1 million for remediation of this waste disposal site and related expenses.

 

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

 

Resource Conservation and Recovery Act

 

The federal Resource Conservation and Recovery Act and corresponding state laws and regulations affect coal mining and gas operations by imposing requirements for the treatment, storage and disposal of hazardous wastes.

 

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

 

28


mining by CONSOL Energy from federal leases for operations developed on such leases. CONSOL Energy’s only operation with a Federal mineral lease is Emery Mine. Emery Mine is not currently mining on the Federal mineral lease and incurred no lease expense in the year ended December 31, 2002. Emery Mine’s asset for advance mining royalty related to the Federal lease was $0.9 million at December 31, 2002. These advance royalties will be amortized on a units-of-production method as the tons related to the lease are mined. In July 2003, we agreed to sell the physical assets, inventory, mineral reserves and operation of the Emery Mine in Utah. The sale is subject to final due diligence and receipt of various approvals and is expected to close in the fourth quarter of 2003.

 

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 nonprice controls affecting wellhead sales of natural gas effective January 1, 1993.

 

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

 

  (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.

 

29


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

 

The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. CONSOL Energy’s gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although CONSOL Energy does not believe that it would be affected by such regulation any differently than other natural gas producers or gatherers. In addition, the Federal Energy Regulatory Commission’s approval of transfers of previously-regulated gathering systems to independent 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 the Form 10-K, quarterly reports on Form

 

30


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.

 

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, which distributes industrial supplies, currently is defending against approximately 21,000 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 in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time and, in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. To date, payments by Fairmont with respect to asbestos cases have not been material. However, there cannot be any assurance that payments in the future with respect to pending or future asbestos cases will not be material to the financial position, results of operations or cash flows of CONSOL Energy.

 

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

 

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

 

None.

 

PART II

 

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

 

Common Stock Market Prices and Dividends

 

Our common stock is listed on the New York Stock Exchange. 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.

 

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     High

   Low

   Dividends

Fiscal Year 2001

              

Quarter Ended September 30, 2000

   21.06        15.00    .28

Quarter Ended December 31, 2000

   28.00    16.13    .28

Quarter Ended March 31, 2001

   37.70    24.88    .28

Quarter Ended June 30, 2001

   42.48    25.00    .28

Six Month Transition Period Ended December 31, 2001

              

Quarter Ended September 30, 2001

   28.50    18.30    .28

Quarter Ended December 31, 2001

   28.45    21.41    .28

Twelve Month Period Ended December 31, 2002

              

Quarter Ended March 31, 2002

   27.49    21.19    .28

Quarter Ended June 30, 2002

   28.32    21.25    .14

Quarter Ended September 30, 2002

   21.54    9.80    .14

Quarter Ended December 31, 2002

   17.90    10.65    .14

 

On March 12, 2003, there were approximately 11,000 holders of record of our common stock.

 

Our Board of Directors intends to continue its policy of paying quarterly dividends. However, the future declaration and payment of dividends and the amount of dividends will depend upon, among other things, general business conditions, our financial results, contractual and legal restrictions on our payment of dividends, our credit rating, our planned investments and such other factors as our Board of Directors deems relevant. Our credit facilities currently do not contain covenants restricting our ability to declare and pay dividends, except in the event of default.

 

EXECUTIVE OFFICERS

 

The following is a list of CONSOL Energy’s executive officers, their ages as of February 1, 2003 and their positions and offices held with CONSOL Energy.

 

Name


   Age

  

Position


J. Brett Harvey

   52    President and Chief Executive Officer and Director

Christoph Koether

   44    Executive Vice President—Administration and Director

Peter B. Lilly

   54    Chief Operating Officer—Coal

Ronald E. Smith

   54    Executive Vice President—Engineering Services, Environmental Affairs & Exploration

William J. Lyons

   54    Senior Vice President and Chief Financial Officer

Daniel L. Fassio

   55    Vice President—General Counsel and Secretary

 

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. Mr. Harvey is a member of the Board of Directors of the National Mining Association, the National Coal Council and the Utah Mining Association.

 

Christoph Koether has been Executive Vice President—Administration since July 2001 and a Director of CONSOL Energy since February 2001. From 1998 until 2001, he held various positions within RWE Rheinbraun AG, including Vice President and Division Head-Corporate Planning and Controlling, and from 1996 to 1997, he was Vice President and Head of the Finance Department and Treasury. He has also been a board member and managing director of various subsidiaries of RWE Rheinbraun AG.

 

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

 

32


President from 1994 to 1995, and as president of Eastern Associated Coal Corporation from 1991 to 1994. He is a former board member of both the National Coal Association and the American Mining Congress.

 

Ronald E. Smith has been Executive Vice President—Engineering Services, Environmental Affairs & Exploration of CONSOL Energy since April 1, 1992.

 

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

 

Daniel L. Fassio has been Vice President, General Counsel and Secretary of CONSOL Energy since March 1994.

 

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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, 2002, June 30, 2001, June 30, 2000 and December 31, 1998, and the six months ended December 31, 2001 and June 30, 1999 are derived from our audited consolidated financial statements. The selected consolidated financial data for, and as of the end of, the twelve months ended December 31, 2001 and the six months ended December 31, 2000, are derived from our unaudited consolidated financial statements, and in the opinion of management include all adjustments, consisting only of normal recurring accruals, that are necessary for a fair presentation of our financial position and operating results for these periods. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and the financial statements and related notes included in this report. In 1999, we changed our fiscal year from a calendar year to a fiscal year ended June 30. In 2001, we changed our fiscal year from a fiscal year ended June 30 to a fiscal year ended December 31 in order to coordinate reporting periods with our majority shareholder commencing with the fiscal year started January 1, 2002.

 

STATEMENT OF INCOME DATA
(In thousands except per share data)
  Twelve Months Ended
December 31,


   

Six Months Ended

December 31,


 

Twelve Months Ended

June 30,


   

Six Months
Ended June 30,

1999


 

Twelve Months
Ended
December 31,

1998


    2002

    2001

    2001

    2000

  2001

    2000

     
          (Unaudited)           (Unaudited)                    

Revenue:

                                                         

Sales (1)

  $ 2,003,345     $ 2,095,463     $ 964,460     $ 992,201   $ 2,123,202     $ 2,094,850     $ 1,081,922   $ 2,295,430

Freight (1)

    134,416       159,029       70,314       72,225     160,940       165,934       80,487     230,041

Other income

    45,837       64,526       31,223       37,154     70,457       64,359       28,560     54,562
   


 


 


 

 


 


 

 

Total Revenue

    2,183,598       2,319,018       1,065,997       1,101,580     2,354,599       2,325,143       1,190,969     2,580,033

Costs:

                                                         

Cost of goods sold and other operating charges

    1,543,189       1,585,686       761,146       730,329     1,554,867       1,498,982       790,119     1,590,176

Freight expense

    134,416       159,029       70,314       72,225     160,940       165,934       80,487     230,041

Selling, general and administrative expense

    65,888       61,155       31,493       33,381     63,043       62,164       30,218     59,475

Depreciation, depletion and amortization

    262,873       243,588       120,039       119,723     243,272       249,877       121,237     238,584

Interest Expense

    46,213       43,356       16,564       30,806     57,598       55,289       30,504     48,138

Taxes other than income

    172,479       160,954       80,659       77,771     158,066       174,272       98,244     201,137

Export sales excise tax resolution

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

Restructuring costs

    —         —         —         —       —         12,078       —       —  
   


 


 


 

 


 


 

 

Total Costs

    2,224,021       2,135,648       1,085,617       1,064,235     2,114,264       2,218,596       1,150,809     2,367,551
   


 


 


 

 


 


 

 

Earnings (Loss) before income taxes

    (40,423 )     183,370       (19,620 )     37,345     240,335       106,547       40,160     212,482

Income taxes (benefits)

    (52,099 )     32,164       (20,679 )     3,842     56,685       (493 )     121     37,845
   


 


 


 

 


 


 

 

Net income

  $ 11,676     $ 151,206     $ 1,059     $ 33,503   $ 183,650     $ 107,040     $ 40,039   $ 174,637
   


 


 


 

 


 


 

 

Earnings per share:

                                                         

Basic (2)

  $ 0.15     $ 1.92     $ 0.01     $ 0.43   $ 2.34     $ 1.35     $ 0.62   $ 1.73
   


 


 


 

 


 


 

 

Dilutive (2)

  $ 0.15     $ 1.91     $ 0.01     $ 0.43   $ 2.33     $ 1.35     $ 0.62   $ 1.73
   


 


 


 

 


 


 

 

Weighted average number of common shares outstanding:

                                                         

Basic

    78,728,560       78,671,821       78,699,732       78,584,204     78,613,580       79,499,576       64,784,685     100,820,599
   


 


 


 

 


 


 

 

Dilutive

    78,834,023       78,964,557       78,920,046       78,666,391     78,817,935       79,501,326       64,784,685     100,820,599
   


 


 


 

 


 


 

 

Dividend per share

  $ 0.84     $ 1.12     $ 0.56     $ 0.56   $ 1.12     $ 1.12     $ 0.39   $ 0.90
   


 


 


 

 


 


 

 

 

34


BALANCE SHEET DATA

(In thousands)

   At December 31,

    At June 30,

    At
December 31,


 
     2002

    2001

    2001

    2000

    1999

    1998

 

Working capital (deficiency)

   $ (191,596 )   $ (70,505 )   $ (368,118 )   $ (375,074 )   $ (261,427 )   $ (602,428 )

Total assets

     4,293,160       4,298,732       3,894,971       3,866,311       3,875,026       3,863,390  

Short-term debt

     204,545       77,869       360,063       464,310       345,525       551,719  

Long-term debt (including current portion)

     497,046       545,440       303,561       307,362       326,495       430,888  

Total deferred credits and other liabilities

     2,828,249       2,913,763       2,378,323       2,358,725       2,423,483       2,433,899  

Stockholders’ equity (deficit)

     162,047       271,559       351,647       254,179       254,725       (103,221 )

 

OTHER OPERATING DATA    Twelve Months Ended
December 31,


   Six Months Ended
December 31,


   Twelve Months Ended
June 30,


   Six Months
Ended June 30,


   Twelve Months
Ended
December 31,


     2002

   2001

   2001

   2000

   2001

   2000

   1999

   1998

Coal:

                                                       

Tons sold (in thousands) (3)(4)

     67,308      76,503      35,587      36,590      77,322      78,714      38,553      77,729

Tons produced (in thousands) (4)

     66,230      73,705      34,355      32,508      71,858      73,073      38,244      75,769

Productivity (tons per manday) (4)

     40.18      39.95      37.15      41.60      42.21      44.23      39.86      40.11

Average production cost ($ per ton produced) (4)

   $ 24.73    $ 22.21    $ 23.73    $ 21.93    $ 21.35    $ 20.00    $ 21.47    $ 20.99

Average sales price of tons produced ($ per ton produced) (4)

   $ 26.76    $ 24.66    $ 25.02    $ 23.41    $ 23.93    $ 23.66    $ 25.12    $ 26.41

Recoverable coal reserves (tons in millions) (4)(5)

     4,275      4,365      4,365      4,372      4,411      4,461      4,705      4,755

Number of mining complexes (at period end)

     22      27      27      23      23      22      24      25

Gas:

                                                       

Gross sales volume produced (in billion cubic feet) (4)

     47.20      38.76      20.12      16.21      34.00      16.23      3.05      6.03

Average sale price ($ per mmbtu) (4)

   $ 3.22    $ 4.10    $ 2.67    $ 4.80    $ 5.27    $ 3.06    $ 2.07    $ 2.34

Average costs ($ per mmbtu) (4)

   $ 2.34    $ 2.63    $ 2.35    $ 2.32    $ 2.58    $ 1.80    $ 2.31    $ 2.09

Net estimated proven reserves (in billion cubic feet) (4)(6)

     1,103      1,176      1,176      730      781      747      467      470

 

CASH FLOW STATEMENT DATA

(In thousands)

   Twelve Months Ended
December 31,


    Six Months Ended
December 31,


    Twelve Months Ended
June 30,


    Six Months
Ended June 30,


     Twelve Months
Ended
December 31,


 
     2002

    2001

    2001

    2000

    2001

    2000

    1999

     1998

 

Net cash provided by operating activities

   $ 329,556     $ 347,356     $ 93,084     $ 181,568     $ 435,839     $ 295,028     $ 84,995      $ 395,313  

Net cash used in investing activities

     (339,936 )     (114,160 )     (11,598 )     (131,078 )     (233,321 )     (299,554 )     (100,790 )      (235,918 )

Net cash provided by (used in) financing activities

     6,315       (228,184 )     (82,529 )     (48,419 )     (194,074 )     (10,852 )     8,069        (146,898 )

OTHER FINANCIAL DATA

(In thousands)

                                                                 

Capital expenditures

   $ 295,235     $ 267,698     $ 162,862     $ 109,163     $ 213,999     $ 142,598     $ 105,099      $ 254,515  

EBIT (7)

     (1,230 )     194,330       (2,132 )     65,590       262,052       156,165       68,438        250,089  

EBITDA (7)

     261,643       437,918       117,907       185,313       505,324       406,042       189,675        488,673  

Ratio of earnings to fixed charges (8)

     —         4.59       —         1.85       4.54       2.70       2.19        4.93  

(A)   See Note 27 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 105,463 and 292,736 for the twelve months ended December 31, 2002 and 2001; 220,314 and 82,187 for the six months ended December 31, 2001 and 2000; and 204,335 and 1,750 for twelve months ended June 30, 2001 and 2000. There

 

35


 

were no dilutive employee or non-employee director stock options for any of the previous periods presented.

(C)   Includes sales of coal produced by CONSOL Energy and purchased from third parties. Of the tons sold, CONSOL Energy purchased the following amount from third parties: 2.5 million tons in the twelve months ended December 31, 2002, 2.8 million tons in the twelve months ended December 31, 2001, 1.3 million tons in the six months ended December 31, 2001, 1.5 million tons in the six months ended December 31, 2000, 2.7 million tons in the twelve months ended June 30, 2001, 3.5 million tons in the twelve months ended June 30, 2000, 3.9 million tons in the twelve months ended June 30, 1999, 2.2 million tons in the six months ended June 30, 1999, and 3.2 million tons for the twelve months ended December 31, 1998. Sales of coal produced by equity affiliates were 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 that were produced by equity affiliates. 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 production, sales or reserves equal to CONSOL Energy’s percentage equity ownership. For coal, 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, 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.
(E)   Represents proven and probable reserves at period end.
(F)   Represents proved developed and undeveloped gas reserves at period end.

 

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

 

(In thousands)    Twelve Months Ended
December 31,


    Six Months Ended
December 31,


    Twelve Months Ended
June 30,


    Six Months
Ended June 30,


     Twelve Months
Ended
December 31,


 
     2002

    2001

    2001

    2000

    2001

    2000

    1999

     1998

 

Net Income

   $ 11,676     $ 151,206     $ 1,059     $ 33,503     $ 183,650     $ 107,040     $ 40,039      $ 174,637  

Add: Interest Expense

     46,213       43,356       16,564       30,806       57,598       55,289       30,504        48,138  

Less: Interest Income

     (5,738 )     (5,990 )     (3,734 )     (2,561 )     (4,817 )     (5,671 )     (2,226 )      (10,531 )

Less: Interest Income included in Export Sales Excise Tax Resolution

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

Add: Income Taxes

     (52,099 )     32,164       (20,679 )     3,842       56,685       (493 )     121        37,845  
    


 


 


 


 


 


 


  


Earnings Before Interest and Taxes (EBIT)

     (1,230 )     194,330       (2,132 )     65,590       262,052       156,165       68,438        250,089  

 

36


(In thousands)    Twelve Months Ended
December 31,


   Six Months Ended
December 31,


   Twelve Months Ended
June 30,


   Six Months
Ended June 30,


   Twelve Months
Ended
December 31,


     2002

   2001

   2001

   2000

   2001

   2000

   1999

   1998

Add: Depreciation, Depletion and Amortization

     262,873      243,588      120,039      119,723      243,272      249,877      121,237      238,584
    

  

  

  

  

  

  

  

Earnings Before Interest, Taxes and Depreciation, Depletion and Amortization

   $ 261,643    $ 437,918    $ 117,907    $ 185,313    $ 505,324    $ 406,042    $ 189,675    $ 488,673
    

  

  

  

  

  

  

  


(H)   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, 2002, fixed charges exceeded earnings by $30.6 million. For the six months ended December 31, 2001, fixed charges exceeded earnings by $20.4 million.

 

37


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

 

General

 

CONSOL Energy incurred a loss before income tax of $40.4 million and realized income tax benefits of $52.1 million, resulting in net income for 2002. CONSOL Energy’s net income was $12 million for the twelve month period ended December 31, 2002. This was a 92.3% decline from the net income of $151 million for the twelve month period ended December 31, 2001.

 

Total coal sales for the twelve months ended December 31, 2002 were 67.3 million tons, including our portion of sales by equity affiliates, of which 64.8 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 76.5 million tons for the twelve months ended December 31, 2001, of which 73.7 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. Demand for coal was weak due to the continued sluggish United States economy and the lingering effect of higher than normal customer inventory levels. The decrease in tons sold was also due to the deferral of shipments by our customers during the year to later periods and reduced volumes from requirements contracts.

 

Production from CONSOL Energy operations, including our percentage of the production from equity affiliates, was 66.2 million tons during the twelve months ended December 31, 2002 and 73.7 million tons for the twelve months ended December 31, 2001. Lower production levels were the result of the announced plan to reduce production by seven to eight million tons from planned output for 2002 in order to match anticipated demand. The following mines were idled during the period to implement reduction:

 

Mine


  

Date Idled


  

Date Production Resumed


McElroy

  

May 1, 2002

  

August 5, 2002

Blacksville #2

  

June 17, 2002

  

July 17, 2002

Robinson Run

  

June 17, 2002

  

July 18, 2002

Mine 84

  

June 17, 2002

  

July 22, 2002

Mahoning Valley

  

June 17, 2002

  

November 1, 2002

Humphrey

  

June 17, 2002

  

August 13, 2002

VP#8

  

June 17, 2002

  

July 15, 2002

Shoemaker

  

June 24, 2002

  

August 26, 2002

Rend Lake

  

July 8, 2002

  

Anticipated to remain idle until

market conditions support reopening

 

In addition, the Humphrey, Meigs, Windsor, Muskingum and Dilworth Mines closed permanently in the year ended December 31, 2002. The Loveridge Mine was idled on May 28, 2001 and development work began in the fourth quarter 2002.

 

Sales of coalbed methane gas, including our share of the sales from equity affiliates, increased 21.8% to 47.2 billion cubic feet in the 2002 period from 38.8 billion cubic feet in the 2001 period. The increased sales volume is primarily due to higher production and sales volumes as a result of the purchase of the remaining 50% interest in the Pocahontas Gas Partnership on August 22, 2001. Our average sales price for coalbed methane gas, including our portion of sales from equity affiliates, was $3.22 per million British thermal units in the 2002 period compared with $4.10 per million British thermal units in the 2001 period. The decrease in average sales price was primarily due to reduced demand for gas in the industrial sector and lower demand for gas during the winter heating season that resulted in higher levels of gas in storage in the beginning of the 2002 period compared to the 2001 period. Approximately 85% of our anticipated 2003 production of 52-54 billion cubic feet has been sold at a price of $4.01 per million British thermal unit.

 

In March 2002, our 50% joint venture with Allegheny Energy Supply Company, LLC, an affiliate of one of our largest coal customers, completed an 88-megawatt, gas-fired electricity generating facility which was placed into commercial service on June 25, 2002. The facility has operated for 34,540 megawatt hours and did not have a significant effect on earnings in the 2002 period.

 

38


Effective June 5, 2002, CONSOL Energy’s Board of Directors appointed PricewaterhouseCoopers LLP to serve as the Company’s independent accountant. PricewaterhouseCoopers LLP serves as the independent accountant for RWE AG, a multi-utility holding group headquartered in Essen, Germany, which owns approximately 74 percent of CONSOL Energy’s common stock. PricewaterhouseCoopers LLP replaced Ernst & Young LLP as the Company’s independent accountant.

 

CONSOL Energy continues to convert to a new integrated information technology system provided by SAP AG to support business processes. The new technology is expected to provide cost-effective strategic software alternatives to meet future core business needs. The system will continue to be implemented in stages through 2003 at an estimated total cost of $53 million, $32 million of which has already incurred.

 

Change in Fiscal Year

 

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

 

Results of Operations

 

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

 

Net Income

 

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

 

Revenue

 

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

 

39


Revenues from the sale of company produced coal decreased $101 million, or 5.6%, to $1,694 million in the 2002 period from $1,795 million in the 2001 period. The decrease in company produced coal sales revenues was due mainly to a decrease in the volume of company produced coal sold. Produced coal sales volumes were 63 million tons in the 2002 period, a 9 million ton, or 12.4%, decline from the 72 million tons sold in the 2001 period. The decrease in tons sold was due primarily to lower demand for coal in the 2002 period. Demand was weak primarily due to the continued sluggish United States economy and the lingering effect of higher than normal customer inventory levels. The decrease in tons sold was also due to the deferral of shipments by our customers during the year to later periods and reduced volumes from requirements contracts. The decrease in tons sold was offset, in part, by increases in the average sales price per ton of company produced coal sold. The average sales price for company produced coal was $26.80 in the 2002 period compared to $24.88 in the 2001 period. The increase of $1.92, or 7.7%, reflects the higher prices negotiated in 2001’s more favorable coal market.

 

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

 

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

 

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

 

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

 

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

 

40


Costs

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Miscellaneous cost of goods sold and other operating charges increased $4 million, or 7.9%, to $47 million in the 2002 period from $43 million in the 2001 period. The increase is due mainly to $14 million of equipment removal cost in the 2002 period compared to $9 million in the 2001 period. The increase in the 2002 period was also due to $4 million of contribution expense related to the donation of property to The Conservation Fund and $2 million of expense to recognize an allowance for doubtful accounts related to trade receivables. Bank fees also increased $2 million in the 2002 period related to the renegotiation of our revolving credit facility. The new facility

 

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replaces the previous agreement, which expired on September 20, 2002 and allows for an aggregate of $485 million of commercial paper principal and letters of credit to be issued. Miscellaneous cost of goods sold and other operating charges also increased $9 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material. These increases in cost of goods sold and other charges were offset, in part, by an $18 million reduction in incentive compensation expense. Expense for this item was reduced in the 2002 period because performance targets for 2002 were not achieved.

 

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

 

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

 

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

 

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

 

Taxes other than income increased $11 million, or 7.2%, to $172 million in the 2002 period compared to $161 million in the 2001 period. The increase was due primarily to increased black lung excise taxes, real estate and personal property taxes and state reclamation fee taxes in the 2002 period compared to the 2001 period. In the 2001 period, due to certain black lung excise taxes being declared unconstitutional, $11 million of prior year accruals, which were not paid and were no longer owed, were reversed. The increase in certain taxes was offset by $4 million due to the reduction of 7 million tons of production in the 2002 period compared to the 2001 period. Real estate and personal property taxes increased $8 million in the 2002 period compared to the 2001 period. This increase was due to $3 million of additional taxes related to the properties owned by Windsor Coal Company, Southern Ohio Coal Company, Central Ohio Coal Company, Pocahontas Gas Partnership and Cardinal States Gathering Company which were acquired in 2001. Real estate and personal property taxes also increased $1 million due to expanded permitting at our mining locations. The remaining $4 million increase in real estate and personal property taxes was related to several transactions throughout the 2002 and 2001 periods, none of which were individually material. These increases in taxes other than income were offset, in part, by a $3 million reduction in payroll taxes. The reduction in payroll taxes is primarily due to reduced employee counts as a result of several mines being idled during the 2002 period. Taxes other than income also decreased $1 million as a result of various transactions throughout the 2002 and 2001 periods, none of which were individually material.

 

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

 

Income Taxes

 

Income taxes represent a $52 million benefit in the 2002 period compared to $32 million of expense in the 2001 period. The decrease in tax expense was due mainly to a pre-tax loss of $40 million in the 2002 period compared to pre-tax income of $183 million in the 2001 period without a comparable reduction in percentage depletion tax benefits. Our effective tax rate is sensitive to changes in annual profitability and percentage depletion. The effective rate was 128.9% in the 2002 period compared to 17.5% in the 2001 period. Income taxes were also reduced due to adjusting the provision for income taxes at the time the returns are filed. These adjustments decreased income tax expense by $4 million in the 2002 period and increased income tax expense $1 million for the 2001 period. In the 2002 period, CONSOL Energy also received a $2 million federal income tax benefit from a final agreement resolving disputed federal income tax items for the years 1995 to 1997.

 

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

 

Net Income

 

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

 

Revenue

 

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

 

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

 

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

 

These decreased revenues were partially offset by increased revenues from the sale of company produced coal. Revenues from the sale of company produced coal increased $14 million, or 1.7%, to $836 million in the 2001 transitional period from $822 million in the 2000 six month period. The increase in produced coal sales revenues was due mainly to an increase of $1.62, or 6.9%, in the average sales price per ton sold. The average sales price was $25.07 in the 2001 transitional period compared to $23.45 in the 2000 six month period. The increase in average sales price was due primarily to demand increases and low inventory levels at coal producers. The increase in average sales price was partially offset by a 2 million ton, or 4.8%, decrease in the volume of produced tons sold in

 

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the 2001 transitional period compared to the 2000 six month period. Produced coal sales volumes were 33 million tons in the 2001 transitional period compared to 35 million tons in the 2000 six month period. The decreased sales volumes were due primarily to the decline in production as a result of the suspension of longwall production at Mine 84 early in July 2001. Mine 84 restarted longwall production in early December 2001 at production levels equal to full production levels in the months before production problems were encountered. This start was approximately one month earlier than originally projected. Production shortages were encountered at several other CONSOL Energy mines due to mechanical and geological difficulties. These production declines were offset by the production at several of the mines acquired from American Electric Power on July 2, 2001.

 

Revenues from the sale of purchased coal decreased $4 million, or 7.7%, to $40 million in the 2001 transitional period from $51 million in the 2000 six month period. Sales volumes decreased 11.9% to 1.3 million tons in the 2001 transitional period from 1.5 million tons in the 2000 six month period. The decreased volumes were partially offset by a 4.8% increase in the price per ton of purchased coal sold. The average sales price per ton of purchased coal was $29.84 in the 2001 transitional period compared to $28.49 in the 2000 six month period.

 

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

 

Other income, which consists of interest income, gain or loss on the disposition of assets, equity in earnings of affiliates, service income, royalty income, rental income and miscellaneous income, was $31 million in the 2001 transitional period compared to $37 million in the 2000 six month period. The decrease of $6 million, or 16.0%, was primarily due to the reduction in equity in earnings of affiliates. The reduction in equity in earnings of affiliates was primarily due to the August 22, 2001 purchase of the remaining 50% interest in Pocahontas Gas Partnership and the remaining 25% interest in the Cardinal States Gathering Company. As a result of the acquisition, CONSOL Energy owns 100% of these entities and began to account for them as fully consolidated subsidiaries. Before the acquisition, CONSOL Energy accounted for these companies using the equity method.

 

Costs

 

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

 

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

 

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

 

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

 

Cost of goods sold for closed and idled mine costs increased $13 million to $29 million in the 2001 transitional period from $16 million in the 2000 six month period. The increase is due primarily to a $10 million income adjustment for mine closing and perpetual care liabilities being recognized in the 2000 six month period. The adjustment was the result of updated engineering studies and cost projections for closed and idled locations.

 

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The increase was also due to additional costs related to the closing or idling of Loveridge, Meigs #31 and Mine 84 in the 2001 transitional period compared to the 2000 six month period.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Income Taxes

 

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

 

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Twelve Months Ended June 30, 2001 compared with Twelve Months Ended June 30, 2000

 

Net Income

 

CONSOL Energy’s net income for the year ended June 30, 2001 was $184 million compared with $107 million for the year ended June 30, 2000. The increase of $77 million was primarily due to the resolution of claims by CONSOL Energy related to export sales excise taxes that were declared unconstitutional. Also, net income increased due to increased gas sales volumes and prices, a reversal of accruals for export sales excise taxes which are no longer owed, and the completion of the restructuring program. These increases to net income were partially offset by increased income tax expense primarily due to higher pretax earnings and loss of percentage depletion benefits, reduced revenues from coal sales primarily due to reduced sales volumes, and higher production costs due mainly to adverse geological conditions at Mine 84.

 

Revenue

 

Sales increased $28 million, or 1.4%, to $2,123 million for the 2001 period from $2,095 million for the 2000 period.

 

Revenues from the sale of coalbed methane gas and gathering fees increased $82 million to $130 million in the 2001 period from $48 million in the 2000 period. Average sales prices increased 69.3% to $5.18 per MMbtu for the 2001 period compared to $3.06 per MMbtu for the 2000 period. The increase was also due to higher volumes as a result of the acquisition of Buchanan Production Company and Oakwood Gathering, Inc. on February 25, 2000 and the inclusion of their results for the entire 2001 period.

 

Revenues from the sale of produced coal decreased by $5 million, or 0.3%, to $1,781 million in the 2001 period from $1,786 million in the 2000 period. Produced Coal sales volumes were 73.8 million tons in the 2001 period, a decrease of 1.4 million tons, or 1.9%, from the 75.2 million tons sold in the 2000 period. This was primarily due to lower production at Mine 84 resulting from adverse geological conditions in the 2001 period. In the quarter ended December 31, 2000 and continuing throughout the remainder of the fiscal year ended June 30, 2001, Mine 84 encountered a sandstone intrusion in the coal seam that ran across several longwall coal panels. Because sandstone is harder than coal, mining advance rates were slowed for both longwall and continuous mining machines. Production for Mine 84 was 2.2 million tons in the 2001 period compared to 5.7 million tons for the 2000 period. Production in the quarter ended June 30, 2001 was 0.6 million tons compared to 0.3 million tons in the quarter ended March 31, 2001. Average sales prices increased 1.6% to $24.12 per ton for the 2001 period from $23.74 per ton for the 2000 period. The increase in average sales price was due primarily to demand increases and low inventory levels at both our mines and at our customers’ power stations.

 

Revenues from the sale of purchased coal decreased by $22 million, or 21.4%, to $81 million in the 2001 period from $103 million in the 2000 period. Sales volumes of Purchased Coal were 2.7 million tons in the 2001 period, a decrease of 0.8 million tons, or 21.2%, compared to the 3.5 million tons sold in the 2000 period. The decrease in tons sold primarily reflects a renegotiated contract that allows company-produced coal to be shipped in the 2001 period instead of coal purchased from third parties which was required to be shipped under the contract in the 2000 period. Average sales prices of coal that we purchased remained consistent.

 

Industrial supplies sales decreased $25 million, or 17.7%, to $116 million in the 2001 period from $141 million in the 2000 period due to reduced sales volumes primarily related to sales to various chemical plants. During the 2001 period, the physical assets, inventory and operations associated with 18 industrial and store management sites of Fairmont Supply Company were sold. The sale did not have a material impact on financial position, results of operations or cash flow. Fairmont Supply Company continues to operate 12 customer service locations nationwide.

 

Freight revenue, outside and related party, which represents amounts billed to customers in a sale transaction related to shipping and handling costs, decreased 3.0% to $161 million in the 2001 period from $166 million in the 2000 period. Freight revenue is the amount billed to customers that equals the expense of the transportation.

 

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Other income, which consists of interest income, gain on the disposition of assets, service income, royalty income, rental income, equity in earnings of affiliates and miscellaneous income, increased 9.5% to $70 million in the 2001 period from $64 million in the 2000 period. The increase of $6 million was primarily due to an increase in the equity in earnings of affiliates related to gas, offset in part by a decrease in the gain on disposition of assets and royalty income. Equity in earnings of affiliates related to gas increased primarily due to an increase in volumes sold and sales prices. The gain on sale of assets principally relates to the sale of certain in place coal reserves. CONSOL Energy continually manages its coal reserves and from time-to-time sells non-strategic reserves.

 

Costs

 

Cost of goods sold and other operating charges increased 3.7% to $1,555 million in the 2001 period compared to $1,499 million in the 2000 period.

 

Cost of goods sold for produced coal was $1,207 million for the 2001 period, an increase of $73 million, or 6.4%, from $1,134 in the 2000 period. The increased cost per ton produced is primarily due to adverse geological conditions at Mine 84. Tons per manday decreased 4.6% to 42.2 tons in the 2001 period compared to 44.2 tons in the 2000 period primarily reflecting the adverse geological conditions at Mine 84.

 

Industrial Supplies cost of goods sold decreased 20.2% to $115 million in the 2001 period from $145 million in the 2000 period. The $30 million decrease was due to reduced sales volumes.

 

Purchased coal costs decreased 24.4% to $76 million in the 2001 period from $100 million in the 2000 period. The $24 million decrease was due to a 21.2% decrease in tons sold. The decrease in tons sold primarily reflects a renegotiated contract that allows company-produced coal to be shipped in the 2001 period instead of coal purchased from third parties which was required to be shipped under the contract in the 2000 period.

 

Gas costs increased 108.1% to $47 million in the 2001 period from $22 million in the 2000 period. The $25 million increase was primarily due to higher volumes as a result of the acquisition of Buchanan Production Company and MCNIC Oakwood Gathering Inc. in February 2000. Average cost per million Btu was $1.88 in the 2001 period, a $0.15 increase, or 8.4%, compared to the 2000 period. Average cost per million Btu has increased due primarily to an increase in royalty expense, which is related to the increase in the average sales price of a million Btu sold.

 

Cost of goods sold for closed and idle mine costs increased 21.5% to $60 million in the 2001 period from $49 million in the 2000 period. The $11 million increase was primarily due to the increased costs related to the preparation for the reopening of Loveridge Mine in the 2001 period in order to mine the remaining longwall panel. The longwall panel was mined out and Loveridge was again idled. Idle mine costs were then incurred to recover, refurbish and redeploy the longwall to another CONSOL Energy mine. Closed and idle mine costs also increased due to engineering survey adjustments related to mine closing and reclamation. In the 2000 period, we incurred costs related to the initial idling or closing of the Powhatan, VP#8 and Ohio #11 Mines that were not repeated during the 2001 period.

 

Costs also increased $16 million due to the approval of a new incentive compensation program for eligible full-time employees. This program is designed to increase compensation payable to eligible employees when CONSOL Energy reaches predetermined earnings targets and the employees reach predetermined performance targets.

 

Freight expense decreased 3.0% to $161 million in the 2001 period from $166 million in the 2000 period. Freight expense is billed to customers and the revenues from such billings equals the transportation expense.

 

Selling, general and administrative expenses increased 1.4% to $63 million in the 2001 period compared to $62 million in the 2000 period. The increase of $1 million was primarily due to increased professional consulting fees associated with the review of business processes and information technology systems supporting those processes, offset in part by salary cost savings from the Voluntary Separation Incentive Program implemented in the last half of the fiscal year ended June 30, 2000.

 

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Depreciation, depletion and amortization expense decreased 2.6% to $243 million in the 2001 period compared to $250 million in the 2000 period. The decrease of $7 million was primarily due to reduced depreciation and depletion expense as a result of the scheduled closing of the Powhatan mine due to economically depleted reserves. Depletion and amortization expense was also reduced due to lower production tons in the 2001 period and items becoming fully amortized in the 2000 period. These decreases were offset, in part, by increased depreciation expense related to assets placed in service after the 2000 period and additional depreciation expense on assets received in the acquisition of Buchanan Production Company and MCNIC Oakwood Gathering Inc.

 

Interest expense increased 4.2% to $58 million for the 2001 period compared to $55 million for the 2000 period. The increase of $3 million was due primarily to higher average debt levels outstanding during the 2001 period compared to the 2000 period, along with an increase of 0.2% in average interest rates. Higher debt levels resulted from the issuance of commercial paper to finance the purchase of Buchanan Production Company, MCNIC Oakwood Gathering Inc. and a MCN subsidiary that owns a 50% interest in Cardinal States Gathering Company in February 2000, and the purchase of a 50% joint venture interest in Line Creek mine on December 31, 2000.

 

Taxes other than income decreased 9.3% to $158 million for the 2001 period compared to $174 million for the 2000 period. The decrease of $16 million was due primarily to reduced excise taxes in the 2001 period. As discussed in Note 7 of the Consolidated Financial Statements, CONSOL Energy is no longer required to pay certain excise taxes on export coal sales and, therefore, is no longer accruing for this expense. Due to these taxes on export coal sales being declared unconstitutional, prior year accruals of $11 million which were not paid and are no longer owed, were reversed. The decrease was partially offset by increased state severance taxes due to higher sales prices and increased property taxes due to increased assessments.

 

CONSOL Energy has filed claims with the Internal Revenue Service seeking refunds for these unconstitutional excise taxes that were paid during the period 1991 through 1999. During the 2001 period, CONSOL Energy recognized $93 million of pretax earnings net of other charges and $31 million of interest income related to these claims.

 

Restructuring charges were $12 million in the 2000 period and represent charges for employee severance costs and outside professional consultant costs. These costs related to the review of administrative and research staff functions that began in the quarter ended December 31, 1999. The purpose of the review was to assess the need for and to assist in a restructuring of those functions to enable CONSOL Energy to respond to the cost challenges of the current environment without losing the ability to take advantage of opportunities to grow the business over the longer term.

 

Income Taxes

 

Income taxes were $57 million in the 2001 period compared to a $0.5 million benefit in the 2000 period. The increased effective tax rate in the 2001 period is due mainly to higher pre-tax income, with some related loss of percentage depletion benefits. The effective rate increase was partially offset due to additional gas tax benefits related to the acquisition of Buchanan Production Company, MCNIC Oakwood Gathering Inc. and a MCN subsidiary that owns a 50% interest in Cardinal States Gathering Company in February 2000. Also, the tax benefit in the 2000 period was due primarily to the recording of an $8 million benefit from a final agreement resolving disputed federal income tax items for the years 1992-1994, the recording of a $4 million benefit resulting from filing the federal and various state tax returns for the period January 1, 1998 through December 31, 1998 in the 2000 period and the recording of a $1 million benefit resulting from filing federal and various state tax returns for the period January 1, 1999 through June 30, 1999 in the 2000 period.

 

Critical Accounting Policies

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities in the consolidated financial statements and at the date of the financial statements, as well as the reported amounts of income and expenses during the reporting period. Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K describes the significant accounting policies and methods used in the preparation of the Consolidated Financial Statements. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable.

 

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The following critical accounting policies are materially impacted by judgements, assumptions and estimates used in the preparation of the Consolidated Financial Statements.

 

Other Post Employment Benefits

 

CONSOL Energy provides retiree health benefits to employees that retire with at least 10 years of service and have attained age 55. Our retiree health plans provide health benefits to approximately 11 thousand of our former employees and were partially funded in 2002 by trusts that were exhausted late in 2002 leaving these benefits unfunded for 2003.

 

After our review, various actuarial assumptions, including discount rate, expected trend in health care costs and per capita costs, are used by our independent actuary to estimate the cost and benefit obligations for our retiree health plan. The discount rate is determined each year at the measurement date (normally three months before the year-end date). The discount rate is an estimate of the current interest rate at which the Other Post Employment Benefit liabilities could be effectively settled at the measurement date. In estimating this rate, CONSOL Energy looks to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. For the twelve months ended December 31, 2002, the discount rate was determined to be 6.75% per annum. The discount rate for the six months ended December 31, 2001 and the twelve months ended June 30, 2001 was determined to be 7.25% per annum. Significant changes to interest rates for the rates of returns on instruments that could be used to settle the actuarily determined plan obligations introduce substantial volatility to our costs.

 

Per capita costs on a per annum basis for Other Post Retirement Benefits were assumed to be $3,633 at December 31, 2002. This was a 13.0% increase over the per capita cost on a per annum basis at December 31, 2001. If the actual increase in per capita cost of medical services or other post retirement benefits are significantly greater or less than the projected trend rates, the per capita cost assumption would need to be adjusted annually, which could have a significant effect on the costs and liabilities recognized in the financial statements. The estimated liability recognized in the financial statements at December 31, 2002 was $1.5 billion compared to $1.4 billion at December 31, 2001.

 

At December 31, 2002, the fair value of plan assets for Other Post Retirement Benefits was $5.0 million. Our policy historically has been to pay for these claims from operating cash flow, and not to fund specific amounts into restricted accounts. In 1998, a trust fund valued at approximately $8 million was acquired as part of our acquisition of Rochester and Pittsburgh Coal Company. In 2000, as part of a contract renegotiation, we acquired an additional $115 million that was placed into the trust fund for Other Post Retirement Benefits. After Internal Revenue Service approval, these funds have been drawn down to pay our Other Post Retirement Benefits, including operations other than those acquired as part of the acquisition of the Rochester and Pittsburgh Coal Company. Once these funds are exhausted, we plan to resume paying Other Post Retirement Benefits from operating cash flow. For the twelve months ended December 31, 2002, we paid Other Post Retirement Benefits of approximately $111 million, of which approximately $21 million were paid from operating cash flow.

 

Coal Workers’ Pneumoconiosis

 

CONSOL Energy is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease. CONSOL Energy is also responsible under various state statutes for pneumoconiosis benefits. After our review, our independent actuaries calculate the actuarial present value of the estimated pneumoconiosis obligation based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and discount rates. The discount rate is determined each year at the measurement date (normally three months before the year-end date). The discount rate is an estimate of the current interest rate which the Coal Workers’ Pneumoconiosis liabilities could be effectively settled at the measurement date. In estimating this rate, CONSOL Energy looks to rates of return on high-quality, fixed income investments that receive one of the two highest ratings given by a recognized ratings agency. For the twelve months ended December 31, 2002, the discount rate was 6.75% per annum. The discount rate for the six months ended December 31, 2001 and the twelve months ended June 30, 2001 was 7.25% per annum. In January 2001, the United States Department of Labor amended the regulations implementing the federal black lung laws to give greater weight to the opinion of a claimant’s treating physician, expand the definition of black lung disease and limit the amount of medical evidence

 

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that can be submitted by claimants and respondents. The amendments also alter administrative procedures for the adjudication of claims, which according to the Department of Labor, results in streamlined procedures that are less formal, less adversarial and easier for participants to understand. These and other changes to the federal black lung regulations could result in changes in assumptions used in our actuarial determination of the liability, including interest, disability and mortality assumptions. Our experience to date related to these changes is not sufficient to determine the impact of these changes. These changes could significantly increase our exposure to black lung benefit liabilities. The estimated liability recognized in the financial statements at December 31, 2002 was approximately $462 million compared to $460 million at December 31, 2001.

 

At December 31, 2002, the fair value of plan assets for Coal Workers’ Pneumoconiosis was $17 million. Our policy has been to pay for these claims from operating cash flow, and not to fund specific amounts into restricted accounts. In 1998, a trust fund valued at approximately $18 million was acquired as part of our acquisition of Rochester & Pittsburgh Coal Company. In 2000, as part of a contract renegotiation, we acquired an additional $42 million that was placed into the trust for Coal Workers’ Pneumoconiosis. As part of the acquisition of several mining companies from American Electric Power in 2001, an additional $31 million was placed into a trust fund for Coal Workers’ Pneumoconiosis. After Internal Revenue Service approval, these funds have been used to pay all of CONSOL Energy’s Coal Workers’ Pneumoconiosis benefits. Once this funding is exhausted, we plan to resume paying these benefits from operating cash flow. For the twelve months ended December 31, 2002, we paid Coal Workers’ Pneumoconiosis benefits of approximately $12 million, none of which were paid from operating cash flow.

 

Salaried Pensions

 

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer retirement plans. The benefits for these plans are based primarily on years of service and employees’ compensation near retirement. After our review, our independent actuaries calculate the actuarial present value of the estimated retirement obligation based on assumptions including rates of compensation, mortality rates, retirement age and interest rates. For the year ended December 31, 2002, compensation increases are assumed to range for 3% to 6% depending on age classification. This assumption was also used in the six months ended December 31, 2001. Mortality assumptions were changed in the year ended December 31, 2002 to reflect a more recent actuarial table for mortality than was used in the previous period. Retirement rate assumptions were unchanged for the year ended December 31, 2002. This assumption begins at 5% for employees at age 50 and increases gradually to 100% of employees at age 65. The discount rate is determined each year at the measurement date (normally three months before the year-end date). The discount rate is an estimate of the current interest rate at which the retirement plans could be effectively settled at the measurement date. In estimating this rate, CONSOL Energy looks to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. For the twelve months ended December 31, 2002 the discount rate was 6.75% per annum. The discount rate for the six months ended December 31, 2001 and the twelve months ended June 30, 2001 was 7.25% per annum. Significant changes to any of these assumptions introduce substantial volatility to our costs. The estimated liability at December 31, 2002, was $120.6 million compared to $35.8 million at December 31, 2001. Due to the negative return on plan assets, the difference in the accumulated benefit obligation and the plan assets at December 31, 2002 of approximately $150 million was recognized as a minimum pension liability. At December 31, 2001, the minimum pension liability was approximately $62 million.

 

Workers’ Compensation

 

Workers’ Compensation is a system by which individuals who sustain employment related physical or mental injuries are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation. Workers’ Compensation will also compensate the survivors of workers who suffer employment related deaths. The workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy accrues for this type of liability by recognizing cost when the event occurs that gives rise to the obligation, i.e., when it is probable that the liability has been incurred and the cost can be reasonably estimated. To assist in the determination of this estimated liability CONSOL Energy utilizes the services of third party administrators in various states in which we do business to determine the liability that exists for workers’ compensation. These third parties provide information that facilitates the estimation of the liability based on their

 

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knowledge and experience concerning similar past events. The estimated liability recognized in the financial statements at December 31, 2002, including the current portion, was approximately $317 million compared to $322 million at December 31, 2001. CONSOL Energy’s policy has been to provide for workers’ compensation benefits from operating cash flow. No funding has been provided to cover these benefits. For the twelve months ended December 31, 2002, we made payments for workers’ compensation benefits of approximately $79 million, all of which was paid from operating cash flow. These payments included a one-time workers’ compensation payment of approximately $22 million made to the state of West Virginia.

 

Reclamation and Mine Closure Obligations

 

The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. CONSOL Energy accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation and mine-closing liabilities, which are based upon permit requirements and CONSOL Energy engineering expertise related to these requirements, including the current portion, were approximately $391 million at December 31, 2002. This liability is reviewed annually by CONSOL Energy management and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental regulations change significantly.

 

We have reviewed the impacts of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) on the accounting treatment of reclamation, mine closing and gas well closing. This statement requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate to the closure of mines and gas wells and the reclamation of land upon exhaustion of coal and gas reserves. Under previous accounting standards, such obligations were recognized ratably over the life of the producing assets, primarily on a units-of-production basis.

 

Effective January 1, 2003, CONSOL Energy will adopt SFAS No. 143. CONSOL Energy is anticipating the effect to be a gain of approximately $5 million, net of a tax cost of $3 million. At the time of adoption, total assets, net of accumulated depreciation, will increase approximately $59 million, and total liabilities will increase approximately $51 million. The amounts recorded upon adoption are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.

 

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

 

Contingencies

 

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

 

Deferred Taxes

 

CONSOL Energy accounts for income taxes in accordance with Statement of Financial Accounting Standard No. 109, “Accounting for Income Taxes” (SFAS No. 109) which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax

 

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basis of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2002, CONSOL Energy has deferred tax assets in excess of deferred tax liabilities of approximately $513 million. The deferred tax assets are evaluated annually to determine if a valuation allowance is necessary. To date, no valuation allowance has been recognized because CONSOL Energy has determined that it is more likely than not that these deferred tax assets will be realized.

 

The purchase price allocation for the acquisition of Windsor Coal Company, Southern Ohio Coal Company and Central Ohio Coal Company was completed in the twelve months ended December 31, 2002. As a result, the $174 million of deferred tax assets initially recorded in the preliminary purchase price allocation was reversed. The change in the purchase price allocation is reflected in the 2002 balance sheet. See Note 2 of the Notes to the Consolidated Financial Statements.

 

Realization of our deferred tax assets is principally dependent upon our achievement of projected future non-coal mining taxable income. Our judgments regarding future profitability may change due to future market conditions, our ability to continue to successfully execute our business strategy and other factors. These changes, if any, may require possible valuation allowances to be recognized. These allowances could materially impact net income.

 

Coal and Gas Reserve Values

 

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

 

    geological conditions;

 

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

 

    the assumed effects of regulations and taxes by governmental agencies;

 

    assumptions governing future prices; and

 

    future operating costs.

 

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

 

Certain Trends and Uncertainties

 

In addition to the trends and uncertainties described in Item I of this Annual Report on Form 10-K under “Coal Operations—Competition,” “Gas Operations—Competition” and “Regulations” and in Critical Accounting Policies and elsewhere in this “Management’s Discussion and Analysis of Results of Operations and Financial Condition,” CONSOL Energy is subject to the trends and uncertainties set forth below.

 

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

 

We are highly leveraged. At December 31, 2002, we had outstanding approximately $701 million in aggregate principal amount of indebtedness, including capital leases, and total stockholders’ equity of $162 million.

 

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We have become highly leveraged as a result of our policy of paying dividends. Since 1992, we have paid dividends aggregating $1.2 billion, approximately the amount of our aggregate net income for the same period.

 

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

 

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

 

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

 

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

 

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

 

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

 

Stockholders’ equity was reduced by comprehensive losses of approximately $56 million in 2002 and $37 million in 2001. These losses relate primarily to minimum pension liability as a result of the negative return on plan assets for non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer retirement plans. Comprehensive losses are calculated annually and reflect a number of factors including conditions in the stock markets and interest rates. We cannot predict whether we will be required to recognize such losses in the future. Further comprehensive losses would erode our stockholders’ equity and possibly preclude our paying dividends, which likely would adversely affect our stock price.

 

Recent changes in our credit ratings could adversely affect our costs and expenses.

 

The credit ratings of our long term debt recently have been downgraded and Standard and Poor’s has classed our long-term debt as BB+, a high yield rating. This could adversely affect our ability to borrow and result in more restrictive borrowing terms, including increased borrowing costs, more restrictive covenants and the extension of less open credit. This in turn could affect our internal cost of capital estimates and therefore operational decisions.

 

In recent periods our operating results have deteriorated and we may incur losses in future periods.

 

Although we reported net income for each of the twelve months ended December 31, 2002, the six months ended December 31, 2001 and the twelve months ended June 30, 2001, net income was attributable to income tax benefits in the periods ended December 31, 2002 and 2001 and benefited substantially from export sales excise tax resolution in the twelve months ended June 30, 2001. For the twelve months ended December 31, 2002 and the six months ended December 31, 2001, we incurred losses before income tax benefits of $40.4 million and $19.6 million. Our recent results reflect a number of factors, including a decrease in tons sold as a result of effects of higher than usual customer inventory levels, decreased average sales price for gas in the industrial sector and lower demand for gas during the winter heating season that resulted in high levels of gas storage. These and other conditions beyond our control could continue to affect our business and we may incur losses in the future.

 

We may be unable to comply with restrictions imposed by our credit facilities and other debt agreements, which could result in a default under these agreements.

 

Our credit facility imposes a number of restrictions on us. A failure to comply with these restrictions could adversely affect our ability to borrow under our credit facilities or result in an event of default under these agreements and our other debt. Our credit facility contains financial and other covenants that create limitations on our ability to, among other things, borrow the full amount under our credit facilities, incur additional debt, and

 

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require us to maintain various financial ratios and comply with various other financial covenants. These financial covenants include a funded debt ratio that requires that we maintain a ratio of total indebtedness for borrowed money as of the last day of each quarter to total earnings before interest, taxes, depreciation and amortization and excluding any extraordinary gains or losses for the four quarters ended on that date of not more than 3 to 1 and a ratio for the last four consecutive quarters of total earnings before interest, taxes, depreciation and amortization and excluding any extraordinary gains or losses to total interest payable (including amortization of debt discount) on indebtedness for borrowed money of not less than 4.5 to 1. Our ability to comply with these restrictions depends upon our operating results, which recently have deteriorated from earlier periods and which continue to be affected by the sluggish economy and other events beyond our control. As a result, we may be unable to comply with these covenants and other restrictions in our credit facility. In the event of a default, our lenders could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we might not be able to pay these amounts, or we might be forced to seek an amendment to our debt agreements which could make the terms of these agreements more onerous for us. Failure to comply with these restrictions, even if waived by our bank lenders, also could adversely affect our credit ratings, which could increase the costs of debt financings to us and impair our ability to obtain additional debt financing.

 

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

 

We compete with coal producers in various regions of the United States for domestic sales, and we compete both with domestic and foreign coal producers for sales in international markets. 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. We sell coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

During the twelve months ended December 31, 2002, approximately 82% of the coal we produced was sold under contracts with terms of one year or more. If a substantial portion of our long-term contracts are modified or terminated, we would be adversely affected to the extent that we are unable to find other customers at the same level of profitability. In general, our long-term contracts have a two to three year average term. The profitability of our long-term coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, and includes our production costs and other factors. Price changes, if any, provided in long term supply contracts are not intended to reflect our cost increases, and therefore increases in our costs may reduce our profit margins. In addition, in periods of declining market prices, provisions for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility. As a result, we may not be able to obtain long-term agreements at favorable prices (compared to either market conditions, as they may change from time to time, or our cost structure) and long-term contracts may not contribute to our profitability.

 

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

 

During the twelve months ended December 31, 2002, Allegheny Energy accounted for approximately 15% of our total revenue and American Electric Power accounted for approximately 11% of our total revenue. Our business and operating results could be adversely affected if either one of these customers does not continue to purchase the same amount of coal or gas as it has purchased from us in the past or on terms, including pricing, it has under existing agreements.

 

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

 

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

 

The creditworthiness of our customer base has declined.

 

Our ability to receive payment for coal or gas sold depends on the creditworthiness of our customers. In general, the creditworthiness of our customers has declined. If this trend were to continue, the number of customers with acceptable credit profiles could decline.

 

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

 

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

 

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Disputes with our customers concerning contracts can result in litigation, which could result in our paying substantial damages.

 

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

 

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

 

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

 

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

 

    amounts of rock and other natural materials and other geological conditions;

 

    equipment failures or repair;

 

    fires and other accidents; and

 

    weather conditions.

 

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

 

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

 

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

 

    geological conditions;

 

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

 

    the assumed effects of regulations and taxes by governmental agencies;

 

    assumptions governing future prices; and

 

    future operating costs.

 

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

 

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

 

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

 

    unexpected drilling conditions;

 

    pressure or irregularities in formations;

 

    equipment failures or repairs;

 

    fires or other accidents;

 

    adverse weather conditions;

 

    pipeline ruptures or spills;

 

    compliance with governmental requirements; and

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

For example, we incur and will continue to incur significant costs associated with the investigation and remediation of environmental contamination under the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) and similar state statutes and have been named as a potentially responsible party at Superfund sites in the past. Our costs for these matters, which currently relate predominantly to one site, could exceed our current accruals, which were $2.9 million at December 31, 2002. The discovery of additional contaminants or the imposition of additional clean-up obligations or other liabilities could result in substantially greater costs than we have estimated.

 

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

 

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of exploration or production operations. For example, we often are required to prepare and present to federal, state and local authorities data pertaining to the effect or impact that proposed exploration for or production of coal may have on the environment. Further, private individuals and the public at large possess rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements which restrict our ability to conduct our mining operations or to do so profitably.

 

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

 

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

 

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

 

Other new and proposed reductions in emissions of mercury, nitrogen oxides, particulate matter or greenhouse gases may require the installation of additional costly control technology or the implementation of other

 

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measures, including switching to other fuels. These new and proposed reductions will make it more costly to operate coal-fired plants and could make coal a less attractive fuel alternative to the planning and building of utility power plants in the future. For example, the Environmental Protection Agency would require reduction of nitrogen oxide emissions in 22 eastern states and the District of Columbia and of particulate matter emissions over the next several years. In addition, Congress and several states are now considering legislation to further control air emissions of multiple pollutants from electric generating facilities and other large emitters. To the extent that any new requirements affect our customers, this could adversely affect our operations and results.

 

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

 

The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. We accrue for the costs of current mine disturbance and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation and mine-closing liabilities, which are based upon permit requirements and our experience, were $391 million at December 31, 2002. On January 1, 2003, CONSOL Energy adopted Statement of Financial Accounting Standards No. 143 (SFAS 143) to account for the costs related to the closure of mines and gas wells and the reclamation of the land upon exhaustion of coal and gas reserves. This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. As a result of this change in accounting principle, we recognized a gain of $5 million, net of a tax cost of $3 million. At the time of adoption, total assets, net of accumulated depreciation, increased approximately $59 million, and total liabilities increased approximately $51 million. These amounts recorded upon adoption are dependent upon a number of variables, including the estimated future retirement costs, estimated proved reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected.

 

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

 

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

 

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

 

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

 

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

 

The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change which is intended to limit or capture emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emissions targets for developed nations. Although the specific emissions targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. The United States Senate is not expected to ratify the emissions targets. If the Kyoto Protocol or other comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States, it could have the effect of restricting the use of coal. Other efforts to reduce emissions of greenhouse gases and federal initiatives to encourage the use of natural gas also may affect the use of coal as an energy source.

 

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

 

The federal Clean Water Act and corresponding state laws affect coal mining operations by imposing restrictions on discharges into regulated waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. New requirements

 

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under the Clean Water Act and corresponding state laws could cause us to incur significant additional costs that adversely affect our operating results.

 

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

 

We provide various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. At December 31, 2002, the current and non-current portions of these obligations included:

 

    post retirement medical and life insurance ($1.5 billion);

 

    coal workers’ black lung benefits ($462 million); and

 

    workers’ compensation ($317 million).

 

These obligations have been estimated based on assumptions, which are described in the notes to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2002. However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. These obligations are unfunded, except for coal workers’ black lung, of which approximately 8% was funded at December 31, 2002. In addition, several states in which we operate consider changes in workers’ compensation laws from time to time. Such changes, if enacted, could adversely affect us.

 

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

 

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

 

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

 

Fairmont Supply Company, our subsidiary, is a co-defendant in various asbestos litigation cases which allege that Fairmont distributed industrial supply products containing asbestos. 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 asbestos cases will not be material.

 

One of our subsidiaries, Fairmont Supply Company, which distributes industrial supplies, currently is defending against approximately 21,900 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 in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time and, in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. To date, payments by Fairmont with respect to asbestos cases have not been material. However, payments in the future with respect to pending or future asbestos cases could be material to the financial position, results of operations or cash flows of CONSOL Energy.

 

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

 

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

 

Liquidity and Capital Resources

 

CONSOL Energy generally has satisfied its working capital requirements and funded its capital expenditures and debt-service obligations from cash generated from operations and proceeds from borrowings. A principal source of borrowing is the issuance of commercial paper. At December 31, 2002, CONSOL Energy had an aggregate principal amount outstanding of $203 million of commercial paper. In September 2002, CONSOL Energy entered into a new Senior Credit Facility that provides for an aggregate of $485 million that may be used to pay commercial paper, for issuing letters of credit and for other borrowings. This facility replaces a $400 million credit facility, which expired in September 2002. The current agreement consists of a 364-day $218 million credit facility which expires in September 2003, and a three year $267 million credit facility which expires in September 2005. Interest is based at our option, upon the Prime (Base) Rate or London Interbank Offered Rates (LIBOR) plus a spread, which is dependent on our credit rating. The agreement has various covenants, including covenants that limit our ability to dispose of assets and merge with another corporation. We are also required to maintain a ratio of total consolidated indebtedness to twelve month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) of not more than 3.25 to 1.0 measured quarterly (3.0 to 1.0 for quarters after December 31, 2002). This ratio was 2.57 to 1.0 at December 31, 2002. In addition, we are required to maintain a ratio of twelve month trailing EBITDA to interest expense and amortization of debt of no less than 4.5 to 1.0 measured quarterly. This ratio was 5.66 to 1.0 at December 31, 2002. At December 31, 2002, this facility had $246 million of additional capacity. At February 28, 2003, this facility had $243 million of additional capacity.

 

CONSOL Energy believes that cash generated from operations and its borrowing capacity will be sufficient to meet its working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments and anticipated dividend payments in 2003. Nevertheless, the ability of CONSOL Energy to satisfy its debt service obligations, to fund planned capital expenditures or pay dividends will depend upon its future operating performance, which will be affected by prevailing economic conditions in the coal and gas industries and other financial and business factors, some of which are beyond CONSOL Energy’s control.

 

On March 7, 2002, CONSOL Energy issued $250 million principal amount of 7.875% notes due in 2012. The notes were issued at 99.174% of the principal amount and CONSOL Energy received approximately $246 million of net proceeds. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and premium, if any, and interest on the notes are guaranteed by several CONSOL Energy subsidiaries that incur or guarantee certain indebtedness. The notes are senior unsecured obligations and rank equally with all other unsecured and unsubordinated indebtedness of the guarantors. CONSOL Energy paid approximately $4 million for debt issuance costs related to these notes. The debt issuance costs are being amortized using the straight-line method and are included in the interest expense line on the Income Statement. In connection with the issuance of these notes, CONSOL Energy entered into a financial derivative contract that essentially fixed the underlying treasury rate (the rate upon which the interest rate for the notes was based) at 4.928% per annum. This contract resulted in a net payment of $1.3 million to CONSOL Energy. This receipt was treated as a cash flow hedge and therefore, resulted in other comprehensive income of $0.8 million (net of $0.5 million deferred tax), which will be amortized to interest income over the life of the notes.

 

On July 17, 2002, one of CONSOL Energy’s subsidiaries, CONSOL Energy Australia PTY Limited (CEA), along with Maitland Main Collieries (MMC), entered into a Syndicated Multi-Option Facility Agreement with Australia and New Zealand Banking Group Limited to provide project finance for development and operation of the Glennies Creek Mine located in New South Wales, Australia. CEA and MMC have equal ownership in the

 

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Glennies Creek Mine. Under the agreement, three borrowing facilities were created. In total, these facilities allow CEA to borrow up to $23 million in stages through 2005. The facilities have various payment dates through 2009. Under these agreements, CEA was required to enter into interest rate hedge contracts and foreign currency swap agreements. The LIBOR and Australian Bank Bill Rate exposure was hedged by entering into interest rate swap contracts to provide the required hedge protection of 95% of the forecasted principal outstanding until March 31, 2004. Thereafter, hedge protection of 75% of the forecasted principal outstanding is required. The market value of these contracts was a $0.9 million liability as of December 31, 2002. These contracts were treated as cash flow hedges and, therefore, resulted in other comprehensive loss of $0.6 million (net of $0.3 million deferred tax). Foreign currency swap contracts were executed on July 10, 2002 to permit CEA to purchase Australian dollars at a fixed exchange rate. CEA entered into these swaps in order to minimize exposure to foreign exchange rate fluctuations. Future swap contracts will be made in order to satisfy the requirement to provide protection of the forecasted currency exposure for a rolling two-year period. For accounting purposes, these contracts did not qualify as hedges. As a result, $0.8 million and $0.2 million of income was recorded in CONSOL Energy’s consolidated financial statements for the quarter and year ended December 31, 2002, respectively.

 

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with our gas marketers (selling gas under short-term multi-month contract nominations generally not exceeding one year.) CONSOL Energy has also entered into a single float for fixed swap transaction that qualifies as a financial cash flow hedge which exists parallel to the underlying physical transactions. This transaction resulted in other comprehensive loss of $1.8 million (net of $1.2 million of deferred tax).

 

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

 

Cash Flows

 

Net cash provided by operating activities was $330 million in the twelve months ended December 31, 2002 compared to $347 million in the twelve months ended December 31, 2001. The change in net cash provided by operating activities was primarily due to decreases in net income, as previously discussed, increases in coal inventory, and a one-time workers’ compensation payment of approximately $22 million made to the state of West Virginia. These decreases to operating cash flow were offset, in part, by reduced tax payments related to the refunds received in the 2002 period due to changes in filing positions and the recognition of amounts in the 2001 period attributable to anticipated refunds for excise tax funds previously paid. Approximately $4 million of these receivables have been collected in the 2002 period and $34 million in the 2001 period.

 

Net cash used in investing activities was $340 million in the 2002 period compared to $114 million in the 2001 period. The change in net cash used in investing activities primarily reflects the $336 million received in the acquisition during 2001 of Windsor Coal Company, Southern Ohio Coal Company and Central Ohio Coal Company, reduced by the $175 million cash expenditures for the acquisition of Line Creek Mine Joint Venture, Glennies Creek Mine Joint Venture, the remaining 50% of Pocahontas Gas Partnership and the remaining 25% of Cardinal States Gathering Company in the 2001 period. Cash used in investing activities was also increased due to $27 million of additional capital expenditures in the 2002 period compared to the 2001 period. Capital expenditures were $295 million in the 2002 period compared to $268 million in the 2001 period. Capital expenditures increased due mainly to the expansion of the McElroy preparation plant and the addition of a longwall at this mining complex. These additions were being completed in preparation of increased shipments under the sales contract with American Electric Power signed July 2001. Mines of the companies which we acquired from American Electric Power have been closed. The mines these companies control have been closed and the contract will be satisfied by coal mined from McElroy and other CONSOL Energy mines. The change in net cash used in investing activities was also due to a use of cash for investments in equity affiliates of $68 million in the 2002 period compared to $5 million in the 2001 period. This was primarily due to the $28 million in payments made to 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 and $17 million for the development of our 50% joint-venture in Glennies Creek Mine in Australia. Cash used in investing activities also changed due to cash generated by 50% of Pocahontas Gas Partnership and 25% of Cardinal States Gathering Company through August 22, 2001 when these entities were

 

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accounted for on the equity method. The remaining 50% of Pocahontas Gas Partnership and the remaining 25% of Cardinal States Gathering Company were purchased for approximately $155 million on this date and these entities became fully consolidated. (See footnote 2 of the Audited Statements for additional details of this transaction.)

 

Net cash provided by financing activities was $6 million in the 2002 period. Net cash used in financing activities was $228 million in the 2001 period. The change in net cash provided by or used in financing activities primarily reflects the net proceeds of approximately $246 million from the March 7, 2002 issuance of 7.875% notes due 2012. Net cash provided also increased $22 million due to the reduction of quarterly dividend payments to $0.14 per share beginning with the quarter ended June 30, 2002 from $0.28 per share dividend paid for each previous quarter. Net cash provided also increased due to $16 million of additional payments being made from the proceeds of the notes issued to reduce the outstanding principal balance of commercial paper in the 2001 period than were made in the 2002 period. These sources of cash were offset, in part, by scheduled payments of $66 million made on unsecured notes that matured in 2002.

 

The following is a summary of our significant contractual obligations at December 31, 2002 (in thousands):

 

     Payments due by Year

     Within 1 Year

   2-3 Years

   4-5 Years

   After 5 Years

   Total

Short-term Notes Payable

   $ 204,545    $ —      $ —      $ —      $ 204,545

Long-term Debt

     3,372      50,782      56,536      378,217      488,907

Capital Lease Obligations

     5,603      3,076      —        —        8,679

Operating Lease Obligations

     13,180      22,661      15,878      9,845      61,564
    

  

  

  

  

Total Contractual Obligations

   $ 226,700    $ 76,519    $ 72,414    $ 388,062    $ 763,695
    

  

  

  

  

 

Additionally, we have long-term liabilities relating to other post employment benefits, work-related injuries and illnesses, defined benefit pension plans, mine reclamation and closure, and other long-term liability costs. We estimate the payments, net of any applicable trust reimbursements, related to these items at December 31, 2002 (in thousands) to be:

 

Payments due by Year


Within 1 Year


 

2-3 Years


 

4-5 Years


 

Total


$254,261

  $559,876   $520,259   $1,334,396

 
 
 

 

As discussed in “Critical Accounting Policies” and in the Notes to our Consolidated Financial Statements, our determination of these long-term liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Moreover, in particular, for periods after 2003 our estimates may change from the amounts included in the table, and may change significantly, if our assumptions change to reflect changing conditions. For example, the payments due in years 2-3 include an estimate of approximately $50 million related to a final payout under a long-term coal contract which was entered into in 1984. Under this agreement, CONSOL Energy was reimbursed for estimated post closure reclamation costs plus a contingency over coal shipments made to the customer. Upon final bond release of the affected areas, reclamation costs versus monies received for reclamation over the life of the contract would be actualized.

 

Capital expenditures were $295 million in the 2002 period compared to $268 million in the 2001 period. We currently anticipate capital expenditures for the year ending December 31, 2003 to be $266 million. We also currently anticipate capital expenditures related to investment in affiliates for the year ending December 31, 2003 to be $38 million. However, we may choose to defer certain capital projects in light of operating results. Capital expenditures for pollution abatement and reclamation are projected to be $4 million for the year ending December 31, 2003. Our capital expenditures have been and will be primarily used for replacement of mining and gas equipment, the expansion of mining and gas capacity and projects to improve the efficiency of the mining and gas operations. The projected capital expenditures for 2003 are not committed and are expected to be funded with cash

 

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generated by operations. In addition, cash requirements to fund employee-related, mine closure and other long-term liabilities included above, along with obligations related to long-term debt, capital and operating leases, are expected to be funded with cash generated by operations. If cash flow from operations is not sufficient to cover expenditures in the future, we expect to rely on the issuance of commercial paper. Our commercial paper program currently provides for borrowings, including the issuance of letters of credit and other borrowings, of up to $485 million through September 2003, at which time the facility provides availability for these purposes of $267 million. We intend to seek the extension of the $218 million portion of the credit facility that expires in September 2003.

 

Debt

 

At December 31, 2002, CONSOL Energy had total long-term debt of $497 million outstanding, including current portion of long-term debt of $9 million This long-term debt consisted of:

 

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

 

    An aggregate principal amount of $90 million of unsecured notes which bear interest at fixed rates ranging from 8.21% to 8.28% per annum and are due at various dates between 2003 and 2007;