Edgar Filing: CONSOL ENERGY INC

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$1,334,396

AMENDMENT #1 TO FORM 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(AMENDMENT NO. 1)

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: 333-68987

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 to be held on April 30, 2003, are incorporated by reference in Part III

EXPLANATORY NOTE

We are filing this Amendment No. 1 on Form 10-K/A to our Report on Form 10-K for the period ending December 31, 2002, which was filed on March 21, 2003 (the “Form 10-K”) to amend and restate Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations to include text of the critical accounting policies related to “Coal Workers’ Pneumoconiosis” and “Salaried Pensions” which was inadvertently deleted from the Form 10-K. In addition, as required by Rule 12b-15, promulgated under the Securities Exchange Act of 1934, as amended, our principal executive officer and principal financial officer are providing Rule 13a-14 certifications in connection with this Form 10-K/A and are also filing written statements pursuant to Title 18 United States Code Section1350, as added by Section 906 of the Sarbanes-Oxley Act of 2002. Except as described above, no other changes have been made to the Form 10-K.

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.

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. 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.

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.

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

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 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 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.

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 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. Tons produced per manday were 37.6 in the 2001 transitional period compared to 41.6 in the 2000 six month period. The decline in productivity is mainly due to several mines experiencing mechanical and geological difficulties in the 2001 transitional period.

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

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

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

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

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

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

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

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 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.

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.

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.

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. 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.

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 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.

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 from 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 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.

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 proved reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.

Previous accounting standards generally used the units of production method to match estimated retirement costs with the revenues generated by the producing assets. In contrast, SFAS No. 143 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units of production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines. Because of the long lives of the underlying 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 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

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. 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.

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.

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 the continued sluggish U.S. economy and the lingering effects of higher than usual customer inventory levels. 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. For example, it 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 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. 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. 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 cannot be certain that we will 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. 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. 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.

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

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

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

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

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

During the twelve months ended December 31, 2002, approximately 82% of the coal we produced was sold under contracts with terms of one year or more. 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. 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. As a result, we cannot assure that we will 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) or that they will 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.

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. 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.

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.

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

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

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

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

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

For example, we incur and will continue to incur significant costs associated with the investigation and remediation of environmental contamination under the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) and similar state statutes and 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 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. 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.

A recent court decision which extends prohibitions previously applicable only to surface mines to underground mines as well, could limit or even preclude our use of longwall mining and restrict the operations or require the closing of several of our underground mines.

The United States District Court for the District of Columbia in Citizens Coal Council v. Norton and the National Mining Association held that the Surface Mining Control and Reclamation Act’s prohibitions on surface coal mining within or nearby certain designated areas listed in Section 522(e) of the Act apply to underground mining beneath those areas as well. The Court’s ruling overturned the Office of Surface Mining rule interpreting the Surface Mining Control and Reclamation Act, which confirmed that certain prohibitions on surface mining do not apply to underground mining. These prohibitions would affect a number of our underground mines and

particularly mines employing longwall mining. Future longwall mining of some of our coal reserves may no longer be economically feasible because the large, contiguous coal reserves needed to perform longwall mining would be continually interrupted by the blocks of coal required to be left in place to protect designated areas. The National Mining Association, the Department of Interior and Office of Surface Mining have filed a motion to stay the decision.

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. President Bush has stated that he does not support the Kyoto Protocol and has proposed an alternative to reduce United States emissions of greenhouse gases. 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. We believe that we have obtained all permits required under the Clean Water Act and corresponding state laws and are in substantial compliance with such permits. However, there can be no assurance that new requirements under the Clean Water Act and corresponding state laws will not 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. 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, which is under 10% funded. 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 21,000 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia 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.

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. Although it may be possible to satisfy our obligations under these statutes and regulations, or it may be possible to satisfy the insurance companies requests for collateral, by providing letters of credit or other assurances of payment, we cannot be certain that we can obtain these or that they would not be significantly more costly than surety bonds have been or otherwise impose restrictions on us.

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 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 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 accounted for on the equity method. The remaining 50% of Pocahontas Gas Partnership and the remaining 25% of Cardinal States Gathering Company were purchased on this date and these entities became fully consolidated.

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	$	205	$	—	$	—	$	—	$	205
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	$	22,360	$	76,519	$	72,414	$	388,062	$	559,355

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:

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 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;

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

$15 million aggregate principal amount of borrowings under a term loan facility which allows CONSOL Energy Australia Pty Limited to borrow up to $16.5 million through March 31, 2004. The borrowed funds must be used for expenditures related to the design, construction, and acquisition of longwall mining equipment and infrastructure upgrades for the longwall mining equipment to enable the extraction of coal using longwall mining methods at Glennies Creek Mine, the joint venture owned 50% by CONSOL Energy Australia Pty Limited. Interest is paid quarterly at a rate of LIBOR plus 1.75%. The principal balance is payable in equal installments on March 31 and September 30 commencing March 31, 2006 and ending March 31, 2009.

$32 million in advance royalty commitments with an average interest rate of 7.538% per annum; and

An aggregate principal amount of $8 million of capital leases with an interest rate of 7.05% to 7.5% per annum.

At December 31, 2002, CONSOL Energy had an aggregate principal amount of $203 million of commercial paper outstanding that had maturities remaining of 1 to 30 days with interest rates ranging from 1.65% to 1.95% per annum.

CONSOL Energy’s commercial paper program has been backed by a Senior Revolving Credit facility provided by a bank syndicate. The most recent facility, established in September 2002, provides for an aggregate of $485 million that may be used for commercial paper maturities, letters of credit and borrowings for other corporate purposes. This agreement replaces a $400 million credit facility, which was to expire 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 payable 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 remaining. At February 28, 2003, this facility had $243 million of additional capacity.

At December 31, 2002, four letters of credit have been issued that are supported by the Senior Revolving Credit facility. The letters of credit total $35 million and were issued to the United Mine Workers of America 1992 Benefit Fund, the Illinois Industrial Commission for self insuring workers’ compensation, Old Republic Insurance for self insuring workers’ compensation and the U.S. Department of Labor for self insuring Longshore and Harborworkers’ compensation.

Stockholders’ Equity and Dividends

CONSOL Energy had stockholders’ equity of $162 million at December 31, 2002 and $272 million at December 31, 2001. Stockholders’ equity was reduced by $56 million in 2002 and $38 million in 2001 due to Other Comprehensive Losses. 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. See Consolidated Statements of Stockholders’ Equity and Note 20 of the Notes to Consolidated Financial Statements.

CONSOL Energy paid ordinary cash dividends of $66 million during the twelve months ended December 31, 2002, $44 million during the six months ended December 31, 2001 and $88 million during the twelve months ended June 30, 2001. The Board of Directors declared a dividend on January 27, 2003 of $0.14 per share of common stock for shareholders of record on February 10, 2003, payable on February 28, 2003. The Board of Directors currently intends to pay quarterly dividends on the common stock. The declaration and payment of dividends by CONSOL Energy is subject to the discretion of the Board of Directors, and no assurance can be given that CONSOL Energy will pay such dividends or any additional dividends in the future. The determination as to the payment of dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, the credit ratings of CONSOL Energy, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. Current outstanding indebtedness of CONSOL Energy does not restrict CONSOL Energy’s ability to pay cash dividends, except that the credit facility would not permit dividends in the event of a default.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on CONSOL Energy’s results of operations for the twelve months ended December 31, 2002, six months ended December 31, 2001 or the twelve months ended June 30, 2001.

Recent Accounting Pronouncements

We have reviewed the impacts of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” on the accounting treatment of reclamation, mine closing and gas well closing. 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. 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, as required. The cumulative effect on net income of adopting SFAS No. 143 is expected to be minimal. 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 proved reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.

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

In July 2001, Statement of Financial Accounting Standards No. 144, “Impairment or Disposal of Long-Lived Assets,” was issued and was effective for CONSOL Energy in 2002. The provisions of this statement provide a single accounting model for impairment of long-lived assets.

In June 2002, Statement of Financial Accounting Standards No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (SFAS No. 146) was issued and will be effective for CONSOL Energy for any exit or disposal activities that are initiated after December 31, 2002. This statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 addresses significant issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities. The scope of SFAS No. 146 includes (1) costs to terminate contracts that are not capital leases; (2) costs to consolidate facilities or relocate employees; and (3) termination benefits provided to employees who are involuntarily terminated under the terms of a one-time benefits arrangement that is not an ongoing benefit arrangement or an individual deferred-compensation contract. This statement will be applied prospectively.

In November 2002, Financial Accounting Standards Board Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45) was issued. This Interpretation describes the disclosure requirements of a guarantor’s issuance of certain

guarantees, and clarifies that a guarantor is required to recognize a liability, at the date of issuance, for the fair value of the obligation assumed in issuing the guarantee. The disclosure requirements of FIN 45 are effective for CONSOL Energy for the year ended December 31, 2002, and the initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002.

In December 2002, Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure,” was issued and the disclosure requirements have been adopted by CONSOL Energy for the year ended December 31, 2002. CONSOL Energy is currently evaluating the alternative methods of transition to determine if the Company will change to the fair value based method of accounting for stock-based employee compensation.

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.

EXHIBIT INDEX

(a)(1)		Financial Statement:

		No Financial Statements are required to be presented by CONSOL Energy.

(a)(2)		Financial Statement Schedules:

		No schedules are required to be presented by CONSOL Energy.

(a)(3)		Exhibits filed as part of this Report:

		The response to this portion of Item 15 is submitted as a separate part of this Report.

(b)(1)		Reports on Form 8-K:

		None.

(c)		Exhibits

99.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized and in the capacities indicated, as of the 14^th day of April, 2003.

CONSOL ENERGY INC.

/s/ William J. Lyons

William J. Lyons,

Senior Vice President and Chief Financial

Officer (Duly Authorized Officer and Principal Financial and Accounting Officer)

CERTIFICATIONS

I, J. Brett Harvey, certify that:

1. I have reviewed this annual report on Form 10-K of CONSOL Energy Inc.;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of the annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: April 14, 2003

/s/ J. Brett Harvey
J. Brett Harvey
President, Chief Executive Officer and Director

CERTIFICATIONS

I, William Lyons, certify that:

I have reviewed this annual report on Form 10-K of CONSOL Energy Inc.;

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of the annual report (the “Evaluation Date”); and

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: April 14, 2003

/s/ W. J. Lyons
W. J. Lyons
Senior Vice President and Chief Financial Officer