Edgar Filing: CONSOL ENERGY INC

For the Years

Ended December 31,

Coalbed methane (in millions of cubic feet)

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2005;

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

For the transition period from

Commission file number: 001-14901

CONSOL ENERGY INC.

(Exact name of registrant as specified in its charter)


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

Consol Plaza

1800 Washington Road

Pittsburgh, Pennsylvania 15241

(Address of principal executive offices including zip code)

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

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


Title of each class		Name of exchange on which registered
Common Stock ($.01 par value)		New York Stock Exchange

Securities are registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasonal issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer x Accelerated Filer ¨ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act. Yes ¨ No x

The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 2005, 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 $4,912,300,931.

The number of shares outstanding of the registrant’s common stock as of February 7, 2006 is 92,446,365 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of Consol Energy’s Proxy Statement for the Annual Meeting of Shareholders to be held on May 2, 2006,

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

TABLE OF CONTENTS


		Page
PART I

Item 1.	Business	4

Item 1A.	Risk Factors	33

Item 1B.	Unresolved Staff Comments	42

Item 2.	Properties	42

Item 3.	Legal Proceedings	42

Item 4.	Submission of Matters to a Vote of Security Holders	44

PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	45

Item 6.	Selected Financial Data	46

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	87

Item 8.	Financial Statements and Supplementary Data	89

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	154

Item 9A.	Controls and Procedures	154

Item 9B.	Other Information	154

PART III

Item 10.	Directors and Executive Officers of the Registrant	155

Item 11.	Executive Compensation	156

Item 12.	Security Ownership of Certain Beneficial Owners and Management	157

Item 13.	Certain Relationships and Related Transactions	157

Item 14.	Principal Accounting Fees and Services	157

PART IV

Item 15.	Exhibits and Financial Statement Schedules	158

SIGNATURES		165

FORWARD-LOOKING STATEMENTS

We are including the following cautionary statement in this Report on Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. With the exception of historical matters, the matters discussed in this Report on Form 10-K are forward-looking statements (as defined in Section 21E of the Exchange Act) that involve risks and uncertainties that could cause actual results to differ materially from projected results. In addition to other factors and matters discussed in Item I of this Annual Report on Form 10-K under “Coal Operations—Competition,” “Gas Operations—Competition,” “Regulations,” in Item 1A of this Annual Report on Form 10-K, “Risk Factors,” and in Item 7 of this Annual Report on Form 10-K under “Critical Accounting Policies,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report on Form 10-K. These risks, uncertainties and contingencies include, but are not limited to, the following:

•

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

•

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

•

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

•

uncertainties in estimating our economically recoverable coal and gas reserves;

•

risks in exploring for and producing gas;

•

obtaining governmental permits and approvals for our operations;

•

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

•

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

•

a decrease in the production of our metallurgical coal or a decrease in the price of metallurgical coal could impact our profitability;

•

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

•

replacing our natural gas reserves which if not replaced will cause our gas reserves and gas production to decline;

•

costs associated with perfecting title for gas rights in some of our properties;

•

we need to use unproven technologies to extract coalbed methane on some of our properties;

•

location of a vast majority of our gas producing properties in two counties in southwestern Virginia, making us vulnerable to risks associated with having our gas production concentrated in one area;

•

we do not insure against all potential operating risks;

•

other persons could have ownership rights in our advanced gas extraction techniques which could force us to cease using those techniques or pay royalties;

•

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

•

reliance on major customers;

•

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

•

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

•

the effects of government regulation;

•

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

•

the coalbeds from which we produce methane gas frequently contain water that may hamper production;

•

increased exposure to employee related long-term liabilities;

•

our participation in multi-employer pension plans may expose us to obligations beyond the obligation to our employees;

•

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

•

the outcome of various asbestos litigation cases;

•

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

•

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

Item 1.

Business.

CONSOL Energy’s History

We are a multi-fuel energy producer and energy services provider that primarily serves the electric power generation industry in the United States. That industry generates approximately two-thirds of its output by burning coal or gas, the two fuels we produce. At December 31, 2005, we produced high-Btu bituminous coal from 17 mining complexes in the United States, including joint ventures. Coal produced from our mines has a high-Btu content which creates more energy per unit when burned compared to coals with lower Btu content. As a result, coals with greater Btu content can be more efficient to use. We are the majority shareholder (81.5%) of CNX Gas Corporation. CNX Gas produces pipeline-quality coalbed methane gas from our coal properties in Pennsylvania, Virginia and West Virginia and conventional gas from properties in Tennessee and Virginia. We believe that the use of coal and gas to generate electricity will grow as demand for power increases.

Historically, we rank among the largest coal producers in the United States based upon total revenue, net income and operating cash flow. Our production of approximately 69 million tons of coal in 2005 accounted for approximately 6% of the total tons produced in the United States and approximately 14% of the total tons produced east of the Mississippi River during 2005. We are one of the premier coal producers in the United States by several measures:

•

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

•

We are the largest coal producer east of the Mississippi River;

•

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

•

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

CNX Gas also ranks as one of the largest coalbed methane gas companies in the United States based on both their proved reserves and their current daily production. Our position as a gas producer is highlighted by several measures:

•

Our principal coalbed methane operations produce gas from coal seams (single layers or stratum of coal) with a high gas content;

•

We currently have approximately 173 million cubic feet of gross average daily production;

•

At December 31, 2005, we operated 2,073 wells connected by approximately 1,000 miles of gathering lines and associated infrastructure;

•

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

•

We controlled one of the largest coalbed methane reserve bases among publicly traded oil and gas companies in the United States with approximately 1.1 trillion cubic feet of net proved reserves of gas at December 31, 2005.

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

CONSOL Energy was organized as a Delaware corporation in 1991. We use “CONSOL Energy” to refer to CONSOL Energy Inc. and our subsidiaries, unless the context otherwise requires.

Recent Events

In December 2005, the Board of Directors authorized a common share repurchase program of up to $300 million during the 24-month period beginning January 1, 2006 and ending December 31, 2007. CONSOL has repurchased 155,000 shares through February 7, 2006 at an average price of $69.06 under this program.

In January 2006, CONSOL Energy entered into a coal sales agreement with American Electric Power (AEP) for the sale of up to 82.5 million tons of high-Btu bituminous coal to various AEP coal-fired power stations over a 15-year period beginning in 2007 and running through 2021. The coal will come from the Shoemaker and McElroy mines and will be shipped to AEP power plants that have or will be equipped to have scrubbers. As a result of the new contract, we will begin a major capital improvement project for the Shoemaker Mine, replacing the mine’s older rail haulage system with a new, more efficient conveyor belt haulage system.

In January 2006, CONSOL Energy purchased Mon River Towing and J.A.R. Barge Lines, LP from the Guttman Group, a private concern. The acquisition will increase the size of CONSOL Energy’s towboat fleet from 5 to 18 and increase the number of barges from about 300 to more than 650, increasing coal transportation capacity from 11 million tons to approximately 24 million tons. The transaction closed on January 20, 2006.

On January 18, 2006, CNX Gas Corporation’s registration statement on Form S-1 was declared effective by the U.S. Securities and Exchange Commission. This registration statement covers 27,936,667 shares of CNX Gas common stock. These shares have been approved for listing on the New York Stock Exchange under the symbol “CXG.” CONSOL Energy owns approximately 81.5% of CNX Gas outstanding shares.

Industry Segments

CONSOL Energy has two principal business units: Coal and Gas. The principal activities of the Coal unit are mining, preparation and marketing of steam coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal unit includes four reportable segments. These reportable segments are Northern Appalachian, Central Appalachian, Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines). For the year ended December 31, 2005, the Northern Appalachian aggregated segment includes the following mines: Shoemaker, Blacksville #2, Robinson Run, McElroy, Loveridge, Bailey, Enlow Fork, Mine 84 and Mahoning Valley. For the year ended December 31, 2005, the Central Appalachian aggregated segment includes the following mines: Jones Fork, Mill Creek and Wiley-Mill Creek. For the year ended December 31, 2005, the Metallurgical aggregated segment includes the following mines: Buchanan, Amonate and V.P. #8. The Other Coal segment includes our purchased coal activities, idled mine cost, coal segment business units not meeting aggregation criteria, as well as various other activities assigned to the coal segment but not allocated to each individual mine. The principal activity of the Gas unit is to produce pipeline quality methane gas for sale primarily to gas wholesalers. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years ended December 31, 2005, 2004 and 2003 is included in Note 28 of Notes to Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.

Coal Operations

Mining Complexes

At December 31, 2005, CONSOL Energy had 17 mining complexes, including an entity of which we own 49%, located in the United States.

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

LOGO

The following table provides the location of CONSOL Energy’s mining complexes and the coal reserves associated with each.

CONSOL ENERGY MINING COMPLEXES

Proven and Probable Assigned and Accessible Coal Reserves as of December 31, 2005 and 2004


Mine/Reserve	Location	Reserve Class	Coal Seam	Average Seam Thickness (feet)	As Received Heat Value(1) (Btu/lb)		Recoverable Reserves(2)					Recoverable Reserves (tons in Millions) 12/31/2004
Mine/Reserve	Location	Reserve Class	Coal Seam	Average Seam Thickness (feet)	Typical	Range	Owned (%)		Leased (%)		Tons in Millions 12/31/2005
ASSIGNED—OPERATING
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)
Enlow Fork	Enon, PA	Assigned	Pittsburgh	5.3	13,030	12,950 – 13,150	94	%	6	%	193.1	50.9
		Accessible	Pittsburgh	5.4	12,980	12,900 – 13,100	75	%	25	%	185.1	164.9
Bailey	Enon, PA	Assigned	Pittsburgh	5.7	13,040	12,950 – 13,150	19	%	81	%	62.9	86.0
		Accessible	Pittsburgh	5.7	12,990	12,900 – 13,100	44	%	56	%	144.2	142.6
Mine 84	Eighty Four, PA	Assigned	Pittsburgh	5.6	13,120	12,950 – 13,250	54	%	46	%	41.5	45.4
		Accessible	Pittsburgh	5.4	13,050	12,880 – 13,180	88	%	12	%	58.5	58.5
McElroy	Glen Easton, WV	Assigned	Pittsburgh	5.9	12,570	12,450 – 12,650	100	%	—	%	208.2	166.2
		Accessible	Pittsburgh	5.8	12,530	12,410 – 12,610	99	%	1	%	68.8	—
Shoemaker	Moundsville, WV	Assigned	Pittsburgh	5.6	12,270	12,200 – 12,400	97	%	3	%	62.4	42.2
		Accessible	Pittsburgh	5.6	12,260	11,990 – 12,390	100	%	—	%	35.8	5.2
Loveridge	Fairview, WV	Assigned	Pittsburgh	7.7	13,230	13,150 – 13,350	100	%	—	%	34.2	8.2
		Accessible	Pittsburgh	7.5	13,210	13,130 – 13,330	89	%	11	%	61.6	93.8
Robinson Run	Shinnston, WV	Assigned	Pittsburgh	7.4	12,940	12,600 – 13,300	75	%	25	%	21.1	27.3
		Accessible	Pittsburgh	6.9	12,940	12,600 – 13,300	75	%	25	%	206.2	206.2
Blacksville 2	Wana, WV	Assigned	Pittsburgh	6.6	13,060	12,850 – 13,250	100	%	—	%	16.0	21.2
		Accessible	Pittsburgh	6.8	13,100	12,890 – 13,290	98	%	2	%	55.7	55.7
Mahoning Valley	Cadiz, OH	Assigned	Multiple	4.3	11,570	11,350 – 11,850	99	%	1	%	4.6	4.5
Central Appalachia (Virginia, Southern West Virginia, Eastern Kentucky)
Buchanan	Mavisdale, VA	Assigned	Pocahontas 3	5.7	13,980	13,700 – 14,200	11	%	89	%	54.9	56.6
		Accessible	Pocahontas 3	6.1	13,930	13,650 – 14,150	12	%	88	%	64.4	64.4
VP-8	Rowe, VA	Assigned	Pocahontas 3	5.2	13,610	12,900 – 14,000	—	%	100	%	0.4	0.9
Mill Creek Complex	Deane, KY	Assigned	Multiple	3.8	12,430	12,350 – 12,650	92	%	8	%	14.3	16.8
		Accessible	Multiple	4.4	11,380	11,300 – 11,600	100	%	—	%	0.7	0.7
Jones Fork Complex	Mousie, KY	Assigned	Multiple	3.6	12,530	12,450 – 12,650	37	%	63	%	31.5	33.3
		Accessible	Multiple	3.2	12,330	12,250 – 12,450	61	%	39	%	4.9	4.9
Amonate Complex	Amonate, VA	Assigned	Multiple	3.5	13,100	12,850 – 13,350	38	%	62	%	10.6	11.1
Miller Creek Complex	Delbarton, WV	Assigned	Multiple	8.5	12,000	11,600 – 12,650	—	%	100	%	5.7	6.8
Southern West Virginia Energy(3)	Mingo County, WV	Assigned	Multiple	8.1	12,100	11,600 – 12,650	—	%	100	%	9.3	—
		Accessible	Multiple	7.1	11,900	11,600 – 12,650	—	%	100	%	9.1	—
Western U.S. (Utah)
Emery	Emery Co., UT	Assigned	Ferron I	7.5	12,260	12,000 – 13,000	80	%	20	%	20.0	21.2
		Accessible	Ferron A	8.8	12,150	11,890 – 12,890	47	%	53	%	12.3	12.3
Total Assigned Operating and Accessible											1,698.0	1,407.8

(1)

The heat value shown for assigned reserves is based on the quality of coal mined and processed during the year ended December 31, 2005. The heat value shown for Accessible reserves is based on the same mining and processing methods as for the assigned reserves with adjustments made based on the variability found in exploration drill core samples. The heat values given have been adjusted to include moisture that may be added during mining or processing and for dilution by rock lying above or below the coal seam.

(2)

Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustment for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams that are controlled by ownership or leases.

(3)

Southern West Virginia Energy (SWVE) is a variable interest entity as defined by Interpretation No. 46 “Consolidation of Variable Interest Entities, and Interpretation of ARB No. 51,” in which CONSOL Energy acquired a 49% ownership interest in 2005. Accordingly, reserve tonnage reflects 100% of SWVE.

Excluded from the table above are approximately 111.2 million tons of reserves at December 31, 2005 that are assigned to projects that have not produced coal in 2005 or 2004. These assigned reserves are in the Northern Appalachia (northern West Virginia), Central Appalachia (Virginia and eastern Kentucky) and Illinois Basin (Illinois) regions. These reserves are approximately 56% owned and 44% leased.

CONSOL Energy assigns coal reserves to each of our mining complexes. The amount of coal we assign to a mining complex generally is sufficient to support mining through the duration of our current mining permit. Under federal law, we must renew our mining permits every five years. All assigned reserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured.

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

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

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

Coal Reserves

At December 31, 2005, CONSOL Energy had an estimated 4.5 billion tons of proven and probable reserves. Reserves are the portion of the proven and probable tonnage that meet CONSOL Energy’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels.

Reserves are defined in SEC Industry Guide 7 as follows:

Proven (Measured) Reserves—Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

Probable (Indicated) Reserves—Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

Spacing of points of observation for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). Our estimates for proven reserves have the highest degree of geologic assurance. Estimates for proven reserves are based on points of observation that are equal to or less than 0.5 mile apart. Estimates for probable reserves have a moderate degree of geologic assurance and are computed from points of observation that are between 0.5 to 1.5 miles apart.

An exception is made concerning spacing of observation points with respect to our Pittsburgh coal seam reserves. Because of the well-known continuity of this seam, spacing requirements are 3,000 feet or less for proven reserves and between 3,000 and 8,000 feet for probable reserves.

CONSOL Energy’s estimates of proven and probable reserves do not rely on isolated points of observation. Small pods of reserves based on a single observation point are not considered; continuity between observation points over a large area is necessary for proven or probable reserves.

Our reserve estimates are predicated on information obtained from our ongoing exploration drilling and in-mine sampling programs. Data including coal seam elevation, thickness, and, where samples are available, coal quality is entered into a computerized geological database. This information is then combined with data on ownership or control of the mineral and surface interests to determine the extent of reserves in a given area. Reserve estimates include mine recovery rates that reflect CONSOL Energy’s experience in various types of underground and surface coal mines.

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

Our estimate of proven and probable coal reserves has been determined by CONSOL Energy’s geologists and mining engineers and has not been reviewed by independent experts.

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

CONSOL Energy’s reserves are located in northern Appalachia (60%), central Appalachia (10%), the mid-western United States (17%), the western United States (10%), and in western Canada (3%) at December 31, 2005.

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

CONSOL Energy—UNASSIGNED Recoverable Coal Reserves as of 12/31/05


	As Received Heat Value(1) (Btu/lb)	Recoverable Reserves 12/31/05(2)					Recoverable Reserves (tons in Millions) 12/31/2004
Coal Producing Region	As Received Heat Value(1) (Btu/lb)	Owned (%)		Leased (%)		Tons (in millions)	Recoverable Reserves (tons in Millions) 12/31/2004
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)	10,350-13,330	75	%	25	%	1,233.5	1,360.7
Central Appalachia (Virginia, Southern West Virginia, Eastern Kentucky)	11,300-14,150	48	%	52	%	192.2	194.6
Illinois Basin (Illinois, Western Kentucky, Indiana)	11,480-12,110	38	%	62	%	742.4	850.8
Western U.S. (Montana, Wyoming,)	8,560-9,400	58	%	42	%	439.4	439.4
Western Canada (Alberta)	12,420-12,910	—	%	100	%	129.1	129.1
Total		57	%	43	%	2,736.6	2,974.6

The heat value estimates for Northern Appalachian and Central Appalachian Unassigned coal reserves include adjustments for moisture that may be added during mining or processing as well as for dilution by rock lying above or below the coal seam. The mining and processing methods currently in use are used for these estimates. The heat value estimates for the Illinois Basin, Western U.S. and Western Canada Unassigned reserves are based primarily on exploration drill core data that may not include adjustments for moisture added during mining or processing, or for dilution by rock lying above or below the coal seam.

The following table summarizes our proven and probable reserves as of December 31, 2005 by region and type of coal or sulfur content (sulfur content per million British thermal units). Proven and probable reserves include both assigned and unassigned reserves. The table classifies bituminous coal as high volatile A, B and C. High volatile A, B and C bituminous coals are classified on the basis of heat value. The table also classifies bituminous coals as medium and low volatile which are classified on the basis of fixed carbon and volatile matter. Coal is ranked by the degree of alteration it has undergone since the initial deposition of the organic material. The lowest ranked coal, lignite, has undergone less transformation than the highest ranked coal, anthracite. From the lowest to the highest rank, the coals are: lignite; sub-bituminous; bituminous and anthracite. The ranking is determined by measuring the fixed carbon to volatile matter ratio and the heat content of the coal. As rank increases, the amount of fixed carbon increases, volatile matter decreases, and heat content increases. Bituminous coals are further characterized by the amount of volatile matter present. Bituminous coals with high volatile matter content are also ranked. High volatile “A” bituminous coals have a higher heat content than high volatile “C” bituminous coals. These characterizations of coal allow a user to predict the behavior of a coal when burned in a boiler to produce heat or when it is heated in the absence of oxygen to produce coke for steel production.

CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES

BY PRODUCING REGION AND PRODUCT (IN MILLIONS OF TONS) AS OF DECEMBER 31, 2005


	<1.20 lbs						> 1.20 < 2.50 lbs						> 2.50 lbs						Total		Percentage By Region
	S02/MMBtu						S02/MMBtu						S02/MMBtu
By Region	Low Btu		Med Btu		High Btu		Low Btu		Med Btu		High Btu		Low Btu		Med Btu		High Btu
Northern Appalachia:
Metallurgical:
High Vol A Bituminous	—		—		—		—		—		187.2		—		—		—		187.2		4.1	%
Steam:
High Vol A Bituminous	—		49.4		—		—		10.0		150.5		37.0		123.3		2,171.6		2,541.8		55.9	%
Low Vol Bituminous	—		—		—		—		—		15.9		—		—		—		15.9		0.4	%

Region Total	—		49.4		—		—		10.0		353.6		37.0		123.3		2,171.6		2,744.9		60.4	%
Central Appalachia:
Metallurgical:
High Vol A Bituminous	—		4.9		18.5		—		—		2.1		—		—		—		25.5		0.6	%
Med Vol Bituminous	1.0		1.5		70.0		—		—		—		—		—		—		72.5		1.6	%
Low Vol Bituminous	—		—		138.8		2.3		—		—		—		—		—		141.1		3.1	%
Steam:
High Vol A Bituminous	35.6		18.8		9.0		39.8		3.9		79.5		—		—		11.0		197.6		4.3	%

Region Total	36.6		25.2		236.3		42.1		3.9		81.6		—		—		11.0		436.7		9.6	%
Midwest – Illinois Basin:
Steam:
High Vol B Bituminous	—		—		—		—		66.0		55.0		20.2		336.7		35.5		513.4		11.3	%
High Vol C Bituminous	—		—		—		—		158.1		—		92.0		—		—		250.1		5.5	%

Region Total	—		—		—		—		224.1		55.0		112.2		336.7		35.5		763.5		16.8	%
Northern Powder River Basin:
Steam:
Subbituminous B	—		—		252.7		—		—		—		—		—		—		252.7		5.6	%
Subbituminous C	—		186.6		—		—		—		—		—		—		—		186.6		4.1	%

Region Total	—		186.6		252.7		—		—		—		—		—		—		439.3		9.7	%
Utah – Emery Field:
High Vol B Bituminous	—		—		—		—		32.3		—		—		—		—		32.3		0.7	%

Region Total	—		—		—		—		32.3		—		—		—		—		32.3		0.7	%
Western Canada:
Metallurgical:
Med Vol Bituminous	18.6		86.1		—		—		—		—		—		—		—		104.7		2.3	%
Low Vol Bituminous	22.5		1.9		—		—		—		—		—		—		—		24.4		0.5	%

Region Total	41.1		88.0		—		—		—		—		—		—		—		129.1		2.8	%

Total Company	77.7		349.2		489.0		42.1		270.3		490.2		149.2		460.0		2,218.1		4,545.8		100.0	%

Percent of Total	1.7	%	7.7	%	10.8	%	0.9	%	5.9	%	10.8	%	3.3	%	10.1	%	48.8	%	100.0	%

CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES BY PRODUCT

(MILLIONS OF TONS) AS OF DECEMBER 31, 2005

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


	<1.20 lbs						> 1.20 < 2.50 lbs						> 2.50 lbs
	S02/MMBtu						S02/MMBtu						S02/MMBtu
By Product	Low Btu		Med Btu		High Btu		Low Btu		Med Btu		High Btu		Low Btu		Med Btu		High Btu		Total		Percentage By Product
Metallurgical:
High Vol A Bituminous	—		4.9		18.5		—		—		189.3		—		—		—		212.7		4.7	%
Med Vol Bituminous	19.6		87.6		70.0		—		—		—		—		—		—		177.2		3.9	%
Low Vol Bituminous	22.5		1.9		138.8		2.3		—		—		—		—		—		165.5		3.6	%

Total Metallurgical	42.1		94.4		227.3		2.3		—		189.3		—		—		—		555.4		12.2	%
Steam:
High Vol A Bituminous	35.6		68.2		9.0		39.8		13.9		230.0		37.0		123.3		2,182.6		2,739.4		60.2	%
High Vol B Bituminous	—		—		—		—		98.3		55.0		20.2		336.7		35.5		545.7		12.0	%
High Vol C Bituminous	—		—		—		—		158.1		—		92.0		—		—		250.1		5.5	%
Low Vol Bituminous	—		—		—		—		—		15.9		—		—		—		15.9		0.4	%
Subbituminous B	—		—		252.7		—		—		—		—		—		—		252.7		5.6	%
Subbituminous C	—		186.6		—		—		—		—		—		—		—		186.6		4.1	%

Total Steam	35.6		254.8		261.7		39.8		270.3		300.9		149.2		460.0		2,218.1		3,990.4		87.8	%

Total	77.7		349.2		489.0		42.1		270.3		490.2		149.2		460.0		2,218.1		4,545.8		100.0	%

Percent of Total	1.7	%	7.7	%	10.8	%	0.9	%	5.9	%	10.8	%	3.3	%	10.1	%	48.8	%	100.00	%

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


Region	Low	Medium	High
Northern, Central Appalachia and Canada	< 12,500	12,500-13,000	> 13,000
Midwest	< 11,600	11,600-12,000	> 12,000
Northern Powder River Basin	< 8,400	8,400-8,800	> 8,800
Colorado and Utah	< 11,000	11,000-12,000	> 12,000

Compliance Compared to Non-Compliance Coal

Coals are sometimes characterized as compliance or non-compliance coal. The phrase compliance coal, as it is commonly used in the coal industry, refers to compliance only with sulfur dioxide emissions standards and indicates that when burned, the coal will produce emissions that will meet the current standard without further cleanup. A coal considered a compliance coal for meeting sulfur dioxide standards may not meet an emission standard for a different pollutant such as mercury. Moreover, the term compliance coal is always used with reference to the then-current regulatory limit. The clean air regulations that further restrict sulfur dioxide emissions and will likely reduce significantly the amount of coal that can be labeled compliance. Currently, a compliance coal will meet the power plant emission standard of 1.2 pounds of sulfur dioxide per million British thermal units of fuel consumed. At December 31, 2005, 0.9 billion tons, or 20%, of our coal reserves met the current standard as a compliance coal. However, in March 2005, the U.S. Environmental Protection Agency promulgated new regulations that further restrict emissions. It is possible that no coal will be considered compliance coal with emission standards restricted to a level that requires emissions-control technology to be used regardless of the sulfur content of the coal.

As a result of a 1998 court decision forcing the establishment of mercury emissions standards for power plants, the Environmental Protection Agency has promulgated a new regulatory program in early 2005 for controlling mercury. CONSOL Energy coals have mercury contents typical for their rank and location (approximately 0.05-0.1 parts mercury per million British thermal unit). Because most CONSOL Energy coals have high heating values, they have lower mercury contents (on a pound per British thermal unit basis) than lower rank coals at a given mercury concentration. Eastern bituminous coals tend to produce a greater proportion of flue gas mercury in the ionic or oxidized form (which is captured by scrubbers installed for sulfur control) than sub-bituminous coal, including coals produced in the Powder River Basin. High rank coals also may be more amenable to other methods of controlling mercury emissions, such as by carbon injection. In the case of mercury, the determination of the existence of a compliance coal for mercury will be based on an analysis of the requirements of the new program and may result in a coal that is compliant for sulfur dioxide standards, but non-compliant for mercury.

Production

In the year ended December 31, 2005, 97% of CONSOL Energy’s production came from underground mines and 3% from surface mines. Where the geology is favorable and where reserves are sufficient, CONSOL Energy employs longwall mining systems in our underground mines. For the year ended December 31, 2005, 88% of our production came from mines equipped with longwall mining systems. Underground longwall systems are highly mechanized, capital intensive operations. Mines using longwall systems have a low variable cost structure compared with other types of mines and can achieve high productivity levels compared with those of other underground mining methods. Because CONSOL Energy has substantial reserves readily suitable to these operations, CONSOL Energy believes that these longwall mines can increase capacity at low incremental cost.

The following table shows the production, in millions of tons, for CONSOL Energy’s mines in the year ended December 31, 2005, 2004 and 2003, the location of each mine, the type of mine, the type of equipment used at each mine and the year each mine was established or acquired by us.

Mine

Location

Mine
Type

Mining
Equipment

Transportation

Produced
(in millions)

Year
Established
or Acquired

2005

2004

2003

Northern Appalachia

Enlow Fork

Enon, Pennsylvania

LW/CM

R R/B

9.8

10.2

9.9

1990

Bailey

Enon, Pennsylvania

LW/CM

R R/B

11.1

10.1

9.4

1984

McElroy

Glen Easton, West Virginia

LW/CM

10.4

8.2

6.3

1968

Robinson Run

Shinnston, West Virginia

LW/CM

R CB

6.1

6.3

5.7

1966

Mine No. 84

Eighty Four, Pennsylvania

LW/CM

R R/B T

3.8

4.0

1998

Blacksville 2

Wana, West Virginia

LW/CM

R R/B T

5.3

5.7

5.4

1970

Shoemaker

Moundsville, West Virginia

LW/CM

3.5

3.7

3.8

1966

Loveridge(1)

Fairview, West Virginia

LW/CM

R T

6.4

4.8

—

1956

Mahoning Valley

Cadiz, Ohio

S/L

R T

0.6

0.7

1974

Central Appalachia

Buchanan

Mavisdale, Virginia

LW/CM

1.7

4.4

4.7

1983

VP-8

Rowe, Virginia

LW/CM

1.2

1.5

1.9

1993

Mill Creek(2)

Deane, Kentucky

U/S

2.8

3.8

3.7

1994

Jones Fork(2)

Mousie, Kentucky

U/S

R T

2.9

3.0

1992

Amonate(2)

Amonate, Virginia

U/S

CM/S/L

R T

0.6

0.7

1925

Miller Creek Complex(2)

Delbarton, West Virginia

U/S

CM/S/L

1.2

0.3

—

2004

Southern West Virginia Resources(2)

Mingo County, West Virginia

U/S

CM/S/L

T R

0.5

—

2005

Western U.S.

Emery(3)

Emery County, Utah

LW/CM

1.2

0.3

0.2

1945

Western Canada

Cardinal River(4)

Hinton, Alberta, Canada

S/L

—

0.1

1969

Line Creek(4)

Sparwood, British Columbia, Canada

S/L

—

0.2

2000

Australia

Glennies Creek(5)

Hunter Valley, New South Wales, Australia

LW/CM

—

0.6

2001

S = Surface

U = Underground

LW = Longwall

CM = Continuous Miner

S/L = Stripping Shovel and Front End Loaders

D = Dragline and Dozers

R = Rail

B = Barge

R/B = Rail to Barge

T = Truck

CB = Conveyor Belt

(1)	Complex was in development at December 31, 2003.

(2)	Amonate, Mill Creek, Miller Creek and Jones Fork complexes include facilities operated by independent mining contractors.

(3)	Emery Mine was idled for all or part of the years ended December 31, 2004 and 2003 due to market conditions.

(4)	Sold in February 2003.

(5)	CONSOL Energy’s 50% interest in the Glennies Creek Mine was sold on February 25, 2004.

The amounts shown for tons produced for all periods presented by Cardinal River, Line Creek and Glennies Creek represent 50% of the production of each mine, reflecting our 50% interest in each mine. Cardinal River and Line Creek Mines in western Canada were sold in 2003 and Glennies Creek Mine in Australia was sold in 2004. The amounts shown for Southern West Virginia Energy (SWVE) represent 100% of SWVE production for the period the entity was a variable interest entity which was fully consolidated.

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


	Years Ended December 31,
	2005		2004		2003
Average Sales Price for Ton Produced	$	35.61	$	30.06	$	27.61

During 2005, several major construction projects were completed at our mining complexes. The McElroy Mine clean coal storage facility was completed. This project minimizes downtime due to adverse river conditions. In addition, both longwalls operated for the majority of the year since the expansion project was completed in 2004. These projects contributed to record annual production at the McElroy Mine in 2005. The Bailey Preparation Plant expansion of the coal refuse area and overland refuse conveyor was completed during 2005. This, along with the plant expansion which was completed in 2004, allowed for additional cleaning capacity. These projects provided for record annual production to be achieved at the Bailey Mine in 2005.

Several new major construction projects began at our mining complexes during 2005. Construction of a new preparation plant as well as a new slope and overland belt was started at Robinson Run Mine. This project provides for the reduction in the size of the old, worked out areas of the coal mine and for increased mine production. It is anticipated that the preparation plant will be completed in the third quarter of 2006 and the new slope and overland belt project will be completed during the second quarter of 2007. Also, the Loveridge Mine started construction of a 750-ton underground coal bunker which will allow for increased belt haulage availability. The Bailey Mine began earthwork for the construction of a new slope and overland belt conveyor. This project is forecasted to be completed during the second quarter of 2008. The project will provide for increased mine production through belt availability improvements and enhanced safety by sealing off a majority of the old mine works.

The Buchanan Mine experienced a large rock fall behind its longwall mining section on February 14, 2005. The cave-in created a large air pressure wave that disrupted ventilation and also caused an ignition of methane gas in the area, which caused a fire to start. The mine was temporarily sealed in order to render the atmosphere inert and extinguish the fire. The mine resumed production in June 2005. There was another incident that took place on September 16, 2005 at the Buchanan Mine. The braking system on the production hoist failed causing both the loaded and empty skips to fall down the production shaft. Damage occurred to the skip components, head frame and bottom structural steel which caused production at this location to be halted. The Buchanan Mine resumed production on December 13, 2005 following completion of major replacements and repairs.

In 2005, the Miller Creek surface and underground mining complex completed its first full year of production. Emery Mine in central Utah achieved their highest annual production in 2005. A new joint venture, Southern West Virginia Energy, was completed during 2005. CONSOL Energy acquired 49% ownership interest in this entity which is classified as a variable interest and is fully consolidated. Production started during the third quarter of 2005.

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

The following table sets forth, with respect to properties that we lease to other coal operators, the total royalty tonnage, acreage leased and the amount of income (net of related expenses) we received from royalty payments from other operators for the year ended December 31, 2005, 2004 and 2003.


Year	Total Royalty Tonnage (in thousands)	Total Coal Acreage Leased	Total Royalty Income (in thousands)
2005	19,903	275,290	$	12,669
2004	18,249	242,160	$	6,001
2003	17,633	244,109	$	6,266

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

At December 31, 2005, CONSOL Energy operates approximately 25% of the United States’ longwall mining systems.

The following table ranks the 20 largest underground mines in the United States by tons of coal produced in calendar year 2004.

MAJOR U.S. UNDERGROUND COAL MINES—2004

In millions of tons


Mine Name	Operating Company	Production
Enlow Fork	CONSOL Energy	10.2
Bailey	CONSOL Energy	10.1
Foidel Creek Mine	Twentymile Coal Company	8.7
McElroy	CONSOL Energy	8.2
San Juan	San Juan Coal Company	7.8
SUFCO	Canyon Fuel Company	7.6
West Elk	Mountain Coal Company	6.5
Robinson Run	CONSOL Energy	6.3
Century	American Energy Corp.	5.8
Emerald	Emerald Coal Resources, LP.	5.8
Blacksville 2	CONSOL Energy	5.7
Cumberland	Cumberland Coal Resources, LP.	5.2
Loveridge	CONSOL Energy	4.8
Federal No. 2	Eastern Associated Coal Corp.	4.8
Dotiki	Webster County Coal LLC	4.8
Buchanan	CONSOL Energy	4.4
Powhatan No. 6	The Ohio Valley Coal Company	4.5
Mine 84	CONSOL Energy	4.0
Bowie #2	Bowie Resources, Ltd.	3.9
Shoal Creek	Drummond Company, Inc.	3.8

Source: National Mining Association

Marketing and Sales

We sell coal produced by our mining complexes and additional coal that is purchased by us for resale from other producers. We maintain United States sales offices in Atlanta, Philadelphia and Pittsburgh and an overseas

office in Brussels, Belgium. In addition, we sell coal through agents, brokers and unaffiliated trading companies. In 2005, we sold 71 million tons of coal, including our percentage of sales in equity affiliates and 100% of variable interest entity affiliates that are fully consolidated. Ninety-four percent (94%) of these sales were sold in domestic markets. Our direct sales to domestic electricity generators represented 69% of our total tons sold in 2005. Including equity affiliate sales, we had approximately 135 customers in 2005. During 2005, Allegheny Energy accounted for approximately 10% of our total revenue. No other customers accounted for more than 10% of total revenue in 2005.

Coal Contracts

We sell coal to customers under arrangements that are the result of both bidding procedures and extensive negotiations. We sell coal for terms that range from a single shipment to multi-year agreements for millions of tons. During the year ended December 31, 2005, approximately 91% of the coal we produced was sold under contracts with terms of one year or more. The pricing mechanisms under our multiple-year agreements typically consist of contracts with one or more of the following pricing mechanisms:

•

Fixed price contracts; or

•

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

•

Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices.

Many contracts provide the opportunity to periodically adjust the contract prices. Contract prices may be adjusted as often as quarterly based upon indices which are pre-negotiated. Many of our recently negotiated contracts have had terms generally no longer than three to five years. An exception to this is a 15 year, 82.5 million ton coal sales agreement, entered into in January 2006 but commencing in January 2007. This contract provides for delivery of 2.5 million tons in each of the years 2007 and 2008, 5.5 million tons in 2009 and 6 million tons of coal annually thereafter to electric generating plants operated by American Electric Power Company. This agreement includes a price re-opener provision on 3 million tons in year 2009, 3.5 million tons in years 2010 and 2011 and 2 million tons in each year thereafter. If the parties do not agree on the price at that time, then the annual volume could be reduced, with ultimate early termination of the contract.

The following table sets forth, as of January 17, 2006, the total tons of coal CONSOL Energy is committed to deliver from 2006 through 2010.


	Tons of Coal to be Delivered (in millions of nominal tons)
	2006	2007	2008	2009	2010
(1) Commitments to deliver coal at predetermined prices	64.4	40.5	21.7	7.5	4.7
(2) Commitments to deliver coal at prices to be determined by mutual agreement of the parties, including some agreements which contain predetermined price ranges.	1.0	5.6	13.0	18.9	18.6

	65.4	46.1	34.7	26.4	23.3

The foregoing table does not include an aggregate of 1.0 million tons that we may be required to deliver from 2006 through 2010 upon exercise of rights of customers under executed contracts to buy more coal at predetermined prices.

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

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

Distribution

Coal is transported from CONSOL Energy’s mining complexes to customers by means of railroad cars, river barges, trucks, conveyor belts or a combination of these means of transportation. We employ transportation specialists who negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines, terminal operators, ocean vessel brokers and trucking companies.

At December 31, 2005 we own five towboats, five harbor boats and a fleet of approximately 300 barges to serve customers along the Ohio and Monongahela Rivers. The barge operation allows us to control delivery schedules and has served as temporary floating storage for coal where land storage is unavailable. Approximately 30% of the coal that we produced was shipped on the inland waterways in 2005.

In January 2006, we completed the acquisition of Mon River Towing and J.A.R. Barge Lines, LP. After this transaction has been completed, the combined river and dock operations will have 18 towboats and more than 650 barges.

Competition

The United States coal industry is highly competitive, with numerous producers in all coal producing regions. CONSOL Energy competes against other large producers and hundreds of small producers in the United States and overseas. The five largest producers are estimated by the 2005 National Mining Association Survey to have produced approximately 54% (based on tonnage produced) of the total United States production in 2004. The U.S. Department of Energy reported 1,357 active coal mines in the United States in 2004, the latest year for which government statistics are available. Demand for our coal by our principal customers is affected by:

•

the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power;

•

coal quality;

•

transportation costs from the mine to the customer; and

•

the reliability of supply.

Continued demand for CONSOL Energy’s coal and the prices that CONSOL Energy obtains are affected by demand for electricity, environmental and government regulation, technological developments and the availability and price of competing coal and alternative fuel supplies. We sell coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.

Gas Operations

Our gas operations are primarily conducted by CNX Gas Corporation, an 81.5% subsidiary of CONSOL Energy. CONSOL Energy primarily produces coalbed methane, which is gas that resides in coal seams. In the eastern United States, conventional natural gas fields typically are located in various types of sedimentary

formations at depths ranging from 2,000 to 15,000 feet. Exploration companies often put their capital at risk by searching for gas in commercially exploitable quantities at these depths. By contrast, gas in the coal seams that we drill or anticipate drilling is typically in formations less than 2,500 feet deep which are usually better defined than deeper formations. CONSOL Energy believes that this contributes to lower exploration costs than those incurred by producers that operate in deeper, less defined formations.

Nearly all of our gas production currently is from operations in Central Appalachia. In this region, we operated 1,862 net wells, 952 miles of gathering lines and various compression stations at December 31, 2005. At December 31, 2005, we reported 1,095.2 billion cubic feet of net proved reserves of gas in Central Appalachia, of which approximately 47.9% is developed. Our average daily net production for the month of December 2005 in this region was 130.9 million cubic feet per day.

We have been developing gas production in Northern Appalachia by gathering gas currently being vented to the atmosphere by our mines in the area and by drilling vertical to horizontal wells in un-mined coal seams. In this region, we operate 133 wells at December 31, 2005, and our average daily net production for the month of December 2005 was approximately 7.6 million cubic feet per day. At December 31, 2005, we had 32.5 billion cubic feet of net proved reserves in Northern Appalachia, of which approximately 78.4% is developed. We expect to expand production of gas in this area by drilling additional production wells into the coal seams that we own or control.

We have also been developing gas production in the Tennessee area through a 50% joint venture. In this area, we operated 34.5 wells at December 31, 2005 and our portion of average daily net production for the month of December 2005 was approximately 0.2 million cubic feet per day. At December 31, 2005, our portion of proved net gas reserves for this area was 2.7 billion cubic feet, of which 100.0% were developed.

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

Drilling

The total average daily gross rate of production controlled by CONSOL Energy during the year ended December 31, 2005, was 156.00 million cubic feet. During 2005, 2004 and 2003, we drilled in the aggregate, 225, 235 and 251 development wells, respectively, all of which were productive. The net number of wells for those periods was approximately 225, 228 and 244, respectively. To date, we have not had any dry development wells. The following table illustrates the wells referenced above by geographic region:

Development Wells


	For the Years Ended December 31,
	2005		2004		2003
	Gross	Net	Gross	Net	Gross	Net
Central Appalachia	206	206	229	222	237	237
Northern Appalachia	19	19	6	6	—	—
Tennessee	—	—	—	—	14	7

Total	225	225	235	228	251	244

During 2005, 2004 and 2003, we drilled in the aggregate 15, 17 and 52 exploratory wells, respectively. The net number of wells for those periods was 15, 12 and 36, respectively. Some of the 2003 wells are still being evaluated or are awaiting completion. Two of the wells in Central Appalachia are still being evaluated. Four of the wells in Northern Appalachia and seven wells (3.5 net wells) in Tennessee are also continuing to be evaluated. The wells still being evaluated are immaterial to the financial statements as a whole. In 2004, three

Tennessee area exploration wells (1.5 net wells) drilled in 2002 were expensed as dry wells. Prior to these wells, we have not had any dry exploration wells. The following table illustrates the exploratory wells by geographic region:

Exploratory Wells


	For the Years Ended December 31,
	2005		2004		2003
	Gross	Net	Gross	Net	Gross	Net
Central Appalachia	2	2	—	—	19	16
Northern Appalachia	13	13	7	7	7	7
Tennessee	—	—	10	5	26	13

Total	15	15	17	12	52	36

Production

The following table sets forth CONSOL Energy’s net sales volume production for the periods indicated, including our portion of equity affiliates and intersegment transactions.

Average Sales Prices and Lifting Costs

The following table sets forth the average sales price, net of hedging transactions, and the average net lifting cost for all of our gas production, including our portion of equity interests, for the periods indicated. Lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization.


	For the Years Ended December 31,
	2005		2004		2003
Average gas sales price including effects of financial settlements (per thousand cubic feet)	$	6.08	$	5.09	$	4.14
Average net lifting cost (per thousand cubic feet)	$	0.57	$	0.50	$	0.48

Productive Wells and Acreage

The following table sets forth, at December 31, 2005, the number of CONSOL Energy’s producing wells, developed acreage and undeveloped acreage.


	Gross	Net
Producing Wells	2,073	2,030
Proved Developed Acreage	162,491	159,761
Proved Undeveloped Acreage	39,080	39,080
Unproved Acreage	901,464	694,912

We drilled 225 development wells in 2005, of which 51 wells were in process at December 31, 2005. Nearly all of our development wells and acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied.

We currently plan to drill 290 wells in 2006, including 215 frac wells in Central Appalachia, 23 vertical-to-horizontal wells in Northern Appalachia and 47 conventional wells through our partnership in Tennessee. The wells are exclusive of gob wells, which are expected to number 55. Additionally, we plan to drill 21 frac wells that were carried over from the 2005 drilling program. .

Sales

CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length at both fixed and variable prices. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, other than pipeline outages related to maintenance, we have not failed to deliver quantities required under contract. CONSOL Energy has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. These financial, as well as physical hedges represented approximately 70% of our produced gas sales volumes for the year end December 31, 2005 at an average price of $4.77 per thousand cubic feet. As of December 31, 2005 we expect these transactions will cover approximately 31% of our estimated 2006 production.

We also have an operational balancing agreement with Columbia Gas Transmission Corporation (“Columbia”). This agreement is in accordance with the Council of Petroleum Accountants Societies (COPAS) definition of producer imbalances, whereby the operator controls the physical production and delivery of gas to a transporter. Contracted quantities of gas rarely equal physical deliveries. As the operator, CONSOL Energy is responsible for monitoring this imbalance and requesting adjustments to contracted volumes as circumstances warrant. The imbalance agreement is managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken and paid for by the purchaser. The financial impacts of these balances were $899 thousand expense and $266 thousand reduction of expense for the year ended December 31, 2005 and 2004, respectively.

CONSOL Energy purchased firm transportation capacity on the Columbia Interstate Pipeline due to the potential for curtailments on portions of the capacity allocated to us. We anticipate that there will be on-going curtailments as a result of the increased demand on the Columbia interstate pipeline, however this firm transportation capacity should offset a portion of the expected impacts from these curtailments. As of December 31, 2005, CONSOL Energy has secured firm transportation capacity to cover hedge production. We also participate in the short-term firm capacity markets to manage flows as market conditions dictate.

The hedging strategy and information regarding derivative instruments used are outlined in item 7A, “Qualitative and Quantitative Disclosures About Market Risk”, and in Note 26 to the Consolidated Financial Statements.

Gathering

Our gas operations in Central Appalachia have built separate gathering systems in our gas fields to deliver most of our gas to marketers. Each gathering system begins at the individual wellhead. Gas from wells is transported to market in each case by the Cardinal States Gathering Company’s major gathering system. Cardinal States Gathering Company operates two major gathering trunklines. The first line is a 50-mile, 16-inch line that is capable of transporting 100 million cubic feet of gas per day. This line has processing and compression facilities and connects with a Columbia interstate pipeline located in Mingo County, West Virginia. The second line is a 30-mile, 20-inch line capable of transporting 150 million cubic feet of gas per day. This line also connects with a Columbia interstate pipeline in Wyoming County, West Virginia. This gathering system has a combined capacity of 250 million cubic feet compared with our 2005 annual average gross production 148 million cubic feet. This excess capacity is vital to our plans to continue to grow our production volumes in Central Appalachia.

Gas Reserves

CONSOL Energy’s gas reserves are either owned or leased. Proved gas reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of any royalty ownership. Proved developed and proved undeveloped gas reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Independent petroleum engineers with Schlumberger Data and Consulting Service, prepared the reserve estimates for 2005 presented below. Independent petroleum engineers with Ralph E. Davis Associates Inc. and Schlumberger Data and Consulting Service prepared the reserve estimates for 2004 and 2003 presented below. Proved developed and undeveloped gas reserves are defined by the Securities and Exchange Commission Rule 4.10(a) of Regulation S-X.


	Net Gas Reserves (millions of cubic feet)
	As of December 31,
	2005		2004		2003
	Consolidated Operations	Equity Affiliates	Consolidated Operations	Equity Affiliates	Consolidated Operations	Equity Affiliates
Proved developed reserves	549,574	2,672	395,152	1,489	352,935	843
Proved undeveloped reserves	578,150	—	647,251	896	649,865	738
Total proved reserves	1,127,724	2,672	1,042,403	2,385	1,002,800	1,581

Discounted Future Net Cash Flows

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


	Discounted Future Net Cash Flows ($ in thousands)
	As of December 31,
	2005		2004		2003
Future net cash flows (net of income tax)	$	5,149,937	$	2,872,571	$	2,708,797
Total standardized measure of after-tax discounted future net cash flows	$	1,870,794	$	1,029,538	$	1,011,186

Competition

Competition throughout the country is regionalized. We operate in the eastern United States. CONSOL Energy believes that the gas market is highly fragmented and not dominated by any single producer. We believe that several of our competitors have devoted far greater resources than we have to gas exploration and development. CONSOL Energy believes that competition within our market is based primarily on price and the proximity of gas fields to customers.

Other

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

Power Generation

In March 2002, we entered into a joint venture with Allegheny Energy Supply Company, LLC, an affiliate of one of our largest coal customers, to build an 88-megawatt, gas-fired electric generating facility. This facility was completed in June 2002. This facility is used for meeting peak load demands. The facility is in southwest Virginia and uses coalbed methane gas that we produce. In 2005, 2004 and 2003, the facility operated for a total of 91,622, 33,340 and 17,610 megawatt hours, respectively, and did not have a significant effect on earnings in any period.

Land Resources

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

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

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

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

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

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

Industrial Supply Services

Fairmont Supply Company, a CONSOL Energy subsidiary, is a general-line distributor of mining and industrial supplies in the United States. Fairmont Supply has 12 customer service centers nationwide. Fairmont Supply offers value-added services including on-site stores management and procurement strategies.

Fairmont Supply provides mine supplies to CONSOL Energy’s mining operations. Approximately 52% of Fairmont Supply’s sales in 2005 were made to CONSOL Energy’s mines.

Terminal Services

In 2005, approximately 5.0 million tons of coal were shipped through CONSOL Energy’s subsidiary, CNX Marine Terminal Inc.’s exporting terminal in the Port of Baltimore. Approximately 20% of the tonnage shipped was produced by CONSOL Energy coal mines. The terminal can either store coal or load coal directly into vessels from rail cars. It is also one of the few terminals in the United States served by two railroads, Norfolk Southern and CSX Transportation.

River and Dock Services

CONSOL Energy’s river operations, located in Elizabeth, Pennsylvania, transports coal from our mines with river loadout facilities along the Monongahela and Ohio Rivers in northern West Virginia and southwestern Pennsylvania to customers along these rivers. The river operation employs five company-owned towboats, five harbor boats and approximately 300 barges. In 2005, our river vessels transported a total of 10.6 million tons of coal, of which 7.9 million tons was produced by CONSOL Energy mines.

CONSOL Energy provides dock services at Alicia Dock, located on the Monongahela River in Fayette County, Pennsylvania, north of the Dilworth Mine. CONSOL Energy transfers coal from rail cars to barges for customers that receive coal on the river system.

Coal Waste Disposal Services

CONSOL Energy operates an ash disposal facility on a 61-acre site in northern West Virginia to handle ash residues for coal customers that are unable to dispose of ash on-site at their generating facilities. This facility became operational in early 1994. The ash disposal facility can process 200 tons of material per hour, and normally disposes of approximately 120 thousand tons of fly ash annually. CONSOL Energy has a long-term contract with a cogeneration facility to supply coal and take the residual fly ash and bottom ash. Bottom ash is disposed locally at the cogeneration facility for road construction and other purposes.

Employee and Labor Relations

At December 31, 2005, CONSOL Energy had 7,257 employees, 3,175 of whom were represented by the United Mine Workers of America and covered by the terms of the National Bituminous Coal Wage Agreement of 2002 which will expire on December 31, 2006. This agreement was negotiated with the United Mine Workers of America by the Bituminous Coal Operators’ Association on behalf of its members, which include several of CONSOL Energy’s subsidiaries.

Regulations

The coal mining and gas industry are subject to regulation by federal, state and local authorities on matters such as the discharge of materials into the environment, employee health and safety, permits and other licensing requirements, reclamation and restoration of mining properties after mining or gas operations are completed, management of materials generated by mining and gas operations, surface subsidence from underground mining, water pollution, water appropriation and legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, endangered plant and wildlife protection, limitations on land use, storage of petroleum products and substances that are regarded as hazardous under applicable laws, and management of electrical equipment containing polychlorinated biphenyls, or PCBs. In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for CONSOL Energy’s coal and gas products. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on CONSOL Energy’s mining or gas operations or our customers’ ability to use coal or gas and may require CONSOL Energy or our customers to change their operations significantly or incur substantial costs.

Numerous governmental permits and approvals are required for mining and gas operations. Regulations provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws by individuals or companies no longer affiliated with CONSOL Energy could provide a basis to revoke existing permits and to deny the issuance of additional permits. CONSOL Energy is, or may be, required to prepare and present to federal, state or local authorities data and/or analysis pertaining to the effect or impact that any proposed exploration for or production of coal or gas may have upon the environment and public and employee health and safety. All requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Accordingly, the permits we need for our mining and gas operations may not be issued, or, if issued, may not be issued in a timely fashion. Permits we need may involve requirements that may be changed or interpreted in a manner which restricts our ability to conduct our mining and gas operations or to do so profitably. Future legislation and administrative regulations may increasingly emphasize the protection of the environment, health and safety and, as a consequence, the activities of CONSOL Energy may be more closely regulated. Such legislation and regulations, as well as future interpretations of existing laws, may require substantial increases in equipment and operating costs to CONSOL Energy and delays, interruptions or a termination of operations, the extent of which cannot be predicted.

While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We post surety performance bonds or letters of credit pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, often including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining and gas production for all domestic coal and gas producers. We endeavor to conduct our mining and gas operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining and gas operations occur from time to time. None of the violations to date, or the monetary penalties assessed has been material. CONSOL Energy made capital expenditures for environmental control facilities of approximately $8.6, $1.3 million, and $1.4 million for the year ended December 31, 2005, 2004 and 2003, respectively. CONSOL Energy expects to have capital expenditures of $25.0 for 2006 for environmental control facilities.

Mine Health and Safety Laws

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

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

Black Lung Legislation

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

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

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

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

In addition to the federal legislation, we are also liable under various state statutes for black lung claims.

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

Workers’ Compensation

CONSOL Energy is required to compensate employees for work-related injuries. Several states in which we operate consider changes in workers’ compensation laws from time to time. Such changes, if enacted, could adversely affect CONSOL Energy.

Retiree Health Benefits Legislation

The Coal Industry Retiree Health Benefit Act of 1992 requires CONSOL Energy to make payments to fund the cost of health benefits for our and other coal industry retirees.

In 1995, in a case filed by the predecessor to the National Mining Association (NMA) on behalf of its members, the U.S. District Court for the Northern District of Alabama ordered the Social Security Administration (“SSA”) to recalculate the per-beneficiary premium that the Combined Fund charges assigned operators. The SSA applied the recalculated, lower premium to all assigned operators, including subsidiaries of CONSOL Energy. In 1996, the Combined Fund sued the SSA in the U.S. District Court for the District of Columbia seeking a declaration that the SSA’s original premium calculation was proper. On February 25, 2000, that Court ruled that the original, higher per beneficiary premium was proper. The SSA then retroactively applied the original, higher premium to various coal operators, including subsidiaries of CONSOL Energy, for all plan years prior to October 1, 2003. However, the NMA and certain other coal operators, including subsidiaries of CONSOL Energy, and the Combined Fund filed separate lawsuits in the U.S. District Courts for the Northern District of Alabama and the District of Columbia, respectively, seeking a determination regarding the SSA’s 2003 premium recalculation. Those lawsuits were transferred to the U.S. District Court for the District of Maryland. The U.S. District Court for the District of Maryland ruled that the higher per beneficiary premium was improper but refused to apply that award retroactively until all appeals were exhausted. The legal process is lengthy and its outcome cannot be predicted with certainty. If the courts rule in CONSOL Energy’s favor, the premium differential may be refunded to the company. We do not believe this matter will have a material impact on its cash flows, results of operations or financial condition.

Environmental Laws

CONSOL Energy is subject to various federal environmental laws, including

•

the Surface Mining Control and Reclamation Act of 1977,

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the Clean Air Act,

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the Clean Water Act,

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the Toxic Substances Control Act,

•

the Endangered Species Act,

•

the Comprehensive Environmental Response, Compensation and Liability Act,

•

the Emergency Planning and Community Right to Know Act, and

•

the Resource Conservation and Recovery Act

as administered and enforced by United States Environmental Protection Agency (EPA) and/or authorized state agencies, state laws of similar scope, and other state environmental and conservation laws in each state in which CONSOL Energy operates.

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

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

Surface Mining Control and Reclamation Act

The Surface Mining Control and Reclamation Act (“SMCRA”) establishes minimum national operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. The Act requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. Permits for all mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement (“OSM”) or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards which are more stringent than the requirements of SMCRA and OSM’s regulations and in many instances, have done so. All states in which CONSOL Energy’s active mining operations are located have achieved primary jurisdiction for enforcement of the Act through approved state programs.

SMCRA permit provisions include requirements for coal exploration; baseline environmental data collection and analysis; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; refuse disposal plans; surface drainage control; mine drainage and mine discharge control; and treatment and site reclamation. The mining permit application process, whether state or federal, is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Detailed engineering plans are included for all surface facilities built as part of the mine, including roads, ponds, shafts and slopes, boreholes, portals, pipelines and power lines, excess spoil disposal areas and coal refuse disposal facilities. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required of the OSM Applicant Violator System. We also must list all public and privately-owned structures located with minimum defined distances near to or above our mines and mining facilities. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some mining permits take over a year to prepare, depending on the size and complexity of the mine and often take six months to three years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including through intervention in the courts. The mine operator must submit a bond or otherwise secure the performance of these reclamation obligations, including, as appropriate, a bond sufficient to cover the costs of long-term treatment of mine drainage discharges from closed facilities or ones from which a post-mining discharge is anticipated. The earliest a reclamation bond can be released is five years after reclamation has been achieved. All states impose on mine operators the responsibility for repairing or compensating for damage occurring on the surface as a result of mine subsidence, a possible consequence of longwall or other methods of underground mining, including an obligation to restore or replace water supplies adversely affected by underground mining. All states also impose an obligation on surface mining operations to replace domestic water supplies adversely affected by such operations. In addition, the Abandoned Mine Reclamation Fund, which is part of the SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore unreclaimed and abandoned mine lands closed before 1977. The maximum tax is $0.35 per ton on surface-mined coal and $0.15 per ton on underground-mined coal.

Under the SMCRA, responsibility for unabated violations of SMCRA and other specified “environmental laws,” unpaid civil penalties and unpaid reclamation fees of subsidiaries and affiliates can be imputed to the “parents” and “related companies” if deemed to be owned “or” controlled by such entities. Similar “violations” by independent contract mine operators can also be imputed to other companies which are deemed, according to the regulations, to have “owned” or “controlled” the contract mine operator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked from receiving new permits and revocation of any permits that have been issued since the time of the violations or, in the case of civil penalties and reclamation fees, since the time such amounts became due.

Clean Air Act and Related New Regulations

The federal Clean Air Act and similar state laws and regulations, which regulate emissions into the air, affect coal mining, gas and processing operations primarily through permitting and/or emissions control requirements. In addition, the EPA has issued certain, and is considering further, regulations relating to fugitive dust and coal combustion emissions which could restrict CONSOL Energy’s ability to develop new mines or require CONSOL Energy to modify our operations. In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards (“NAAQS”) for particulate matter which may require some states to change existing implementation plans. As a result of the NAAQS revisions, many areas of the country were reclassified from attainment to non-attainment for fine particulate or ozone in 2004. Because coal mining operations and plants burning coal emit particulate matter, CONSOL Energy’s mining operations and utility customers are likely to be directly affected when the revisions to the NAAQS are implemented by the states. In addition, the EPA is in the process of further revising the NAAQS for particulate matter. It is expected that more stringent NAAQS for particulate matter will be finalized in 2006. Regulations may restrict CONSOL Energy’s ability to develop new mines or could require CONSOL Energy to modify our existing operations.

CONSOL Energy believes we have obtained all necessary permits under the Clean Air Act. The expiration dates of these permits range from November 28, 2006 through June 30, 2008. CONSOL Energy monitors permits required by operations regularly and takes appropriate action to extend or obtain permits as needed.

The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of coal fired electric power generating plants. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. New environmental regulations governing emissions from coal-fired electric generating plants could affect demand for coal as a fuel source and affect the volume of our sales. For example, the federal Clean Air Act places limits on sulfur dioxide and nitrogen dioxide emissions from electric power plants.

Further sulfur dioxide emission reductions are required by the Clean Air Interstate Rules (“CAIR”), which were promulgated by the EPA in 2005. In order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), blend high sulfur coal with low sulfur coal or switch to low sulfur coal or other fuels. The CAIR rules significantly reduce sulfur dioxide emission allowances available to electric power plants. As limits are ratcheted down, very few coals are truly “compliance” coal and the installation of environmental control technology in the form of scrubbers becomes an economic option. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent and timing to which power generators install scrubbers could materially affect our business.

In October 1998, the EPA finalized a rule requiring 22 states in the eastern U.S. that have or contribute to ambient air quality problems to make substantial reductions in nitrogen oxide emissions by June 1, 2004. The installation of additional control measures to achieve these reductions makes it more costly to operate coal-fired power plants and could make coal a less attractive fuel. In addition, reductions in nitrogen oxide emissions can be achieved at a low capital cost through a combination of low nitrogen oxide burners and coal produced in western U.S. coal mines. As a result, changes in current emissions standards could also impact the economic incentives

for eastern U.S. coal-fired power plants to consider using more coal produced in western U.S. coal mines. The CAIR rules promulgated in 2005 already target electric utilities for further resolutions in NOx and impose emissions caps for NOx on electric generating units that take effect in 2010.

In 2005, the EPA finalized the Clean Air Mercury Rule (“CAMR”) which imposes caps on mercury emissions from coal-fired electric generating units. The emission caps take effect in 2010. The CAMR provides for an allocation of mercury emission allowances to individual power plants based on the type of coal fired in the unit. Units firing bituminous coal are allocated less emission allowances than those firing subbituminous coal. In addition, various states have promulgated or are considering more stringent emission limits on mercury emissions from coal-fired electric generating units. The CAMR rule and state regulation of mercury emissions from coal-fired electric generating units could impact the market for coal.

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

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

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

Clean Water Act

The federal Clean Water Act and corresponding state laws affect coal mining and gas operations by imposing restrictions on discharges into regulated surface waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. New requirements under the Clean Water Act and corresponding state laws, including those relating to protection of “impaired water” so designated by individual states through the use of new effluent limitations known as Total Maximum Daily Load (“TMDL”) limits, and anti-degradation regulations which protect state designated “high quality/exceptional use” streams by restricting or prohibiting “discharges” which result in degradation , and these “protecting” streams, wetlands, other regulated water sources and associated riparian lands from the surface impacts of under ground mining, may cause CONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.

The Army Corps of Engineers (the “COE”) is empowered to issue “nationwide” permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Individual permits are required for activities determined to have more significant impacts to waters of the United States. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States, although this Nationwide Permit 21 must be renewed in 2007 to enable its continued use. If Nationwide Permit 21 is not renewed, then sites using that permit will have to apply to the COE to convert any approved Nationwide Permit 21 to individual permits. On October 23, 2003, several citizens groups sued the COE in the U.S. District Court for the Southern District of West Virginia seeking to invalidate “nationwide” permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil

valley fills and refuse impoundments. The plaintiffs sought to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional use of existing nationwide permit approvals until they obtain more detailed “individual” permits. On July 8, 2004, the court issued an order enjoining the further issuance of Nationwide Permit 21 and rescinded certain listed permits where construction of valley fills and surface impoundments had not commenced. On August 13, 2004, the court extended the ruling to all Nationwide Permit 21 within the Southern District of West Virginia. Although we had no operations that were interrupted, based on this decision, we decided to convert certain current and planned applications for Nationwide Permit 21 in southern West Virginia to applications for individual permits. A similar lawsuit was filed on January 27, 2005 in the U.S. District Court for the Eastern District of Kentucky, and other lawsuits may be filed in other states where we operate. Although this lawsuit has not yet been resolved, we have decided to obtain individual Corps permits for our facilities as needed in eastern Kentucky. To date, our operations in other states have not been significantly affected by the lawsuits in eastern Kentucky and southern West Virginia.

Comprehensive Environmental Response, Compensation and Liability Act (Superfund)

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

From time to time, we have been the subject of administrative proceedings, litigation and investigations relating to environmental matters. We have been named as a potentially responsible party at Superfund sites in the past. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us.

Resource Conservation and Recovery Act

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

Federal Coal Leasing Amendments Act

Mining operations on federal lands in the western United States are affected by regulations of the United States Department of the Interior. The Federal Coal Leasing Amendments Act of 1976 amended the Mineral Lands Leasing Act of 1920 which authorized the leasing of federal coal lands for coal mining. The Federal Coal Leasing Amendments Act increased the royalties payable to the United States Government for federal coal leases and required diligent development and continuous operations of leased reserves within a specified period of time. Subtitle D of the Energy Policy Act of 2005 (Pub. L. 109-58) contained the Coal Leasing Amendments Act of 2005, which includes provisions designed to facilitate efficient and economic development of federal coal leases. The United States Department of the Interior has stated that it intends to promulgate new regulations and implement these 2005 amendments. Regulations adopted by the United States Department of the Interior to implement such legislation could affect coal mining by CONSOL Energy from federal coal leases for operations developed that would incorporate such leases. CONSOL Energy’s only operation with federal coal leases is Emery Mine.

Federal Regulation of the Sale and Transportation of Gas

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

Commencing in April 1992, the Federal Energy Regulatory Commission issued Order Nos. 636, 636-A, 636-B, 636-C and 636-D, which require interstate pipelines to provide transportation services separate, or “unbundled,” from the pipelines’ sales of gas. Also, Order No. 636 requires pipeline operators to provide open access transportation on a nondiscriminatory basis that is equal for all natural gas shippers. Although Order No. 636 does not directly regulate CONSOL Energy’s production activities, the Federal Energy Regulatory Commission has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry.

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

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

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

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

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

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

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

The new reporting requirements became effective on September 1, 2000. The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory

Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. CONSOL Energy’s gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although CONSOL Energy does not believe that it would be affected by such regulation any differently than other natural gas producers or gatherers. In addition, the Federal Energy Regulatory Commission’s approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to Federal Energy Regulatory Commission regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future.

CONSOL Energy owns certain natural gas pipeline facilities that we believe meet the traditional tests which the Federal Energy Regulatory Commission has used to establish a pipeline’s status as a gatherer not subject to the Federal Energy Regulatory Commission jurisdiction.

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

State Regulation of Gas Operations—United States

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

Available Information

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

Executive Officers of The Registrant

Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Officers of the Registrant” (included herein pursuant to Item 401 (b) of Regulation S-K).

Item 1A.

Risk Factors.

Investment in our securities is subject to various risks, including risks and uncertainties inherent in our business. The following sets forth factors related to our business, operations, financial position or future financial performance or cash flows which could cause an investment in our securities to decline and result in a loss.

Disruption of rail, barge and other systems that deliver CONSOL Energy’s coal, or of pipeline systems that deliver CONSOL Energy’s gas, or an increase in transportation costs for either product could make CONSOL Energy’s 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, break-downs of locks and damns 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 CONSOL Energy’s gas production partly depends on the availability, proximity and capacity of pipeline systems owned by third parties. Changes in access to pipelines or increased costs of procuring transportation on pipeline systems could adversely affect our operations.

We require a skilled workforce to run our business. If we cannot hire qualified people to meet replacement or expansion needs, we may not be able to achieve planned results.

Most of our workforce is comprised of people with technical skills related to the production of coal and gas. Fifty-five percent of our workforce is 50 years of age or older. Based on our experience, we expect a high percentage of our employees to retire between now and the end of the decade. This will require us to conduct an expanded and sustained effort to recruit new employees to replace those who retire and to fill new jobs as we grow our business. Some areas of Appalachia, most notably in eastern Kentucky, currently have a shortage of skilled labor. Because we have operations in this area, the shortage could make it more difficult to meet our manpower needs and therefore, our results may be adversely affected.

Coal mining is subject to conditions or events beyond CONSOL Energy’s control, which could cause our financial results to deteriorate.

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

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

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amounts of rock and other natural materials intruding into the coal seam and other geological conditions that could affect the stability of the roof and the side walls of the mine;

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equipment failures or repair;

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fires and other accidents; and

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weather conditions.

CONSOL Energy faces uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

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

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

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geological conditions;

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

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the assumed effects of regulations and taxes by governmental agencies;

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assumptions governing future prices; and

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future operating costs, including cost of materials.

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

CONSOL Energy faces uncertainties in estimating proven recoverable gas reserves, and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of our reserves.

Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and time of development expenditures may be incorrect. We have in the past retained the services of independent petroleum engineers to prepare reports of our proved reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing, and production. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our gas and oil properties also will be affected by factors such as:

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geological conditions;

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changes in governmental regulations and taxation;

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assumptions governing future prices;

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the amount and timing of actual production;

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future operating costs, including costs of materials; and

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capital costs of drilling new wells.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

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

The exploration for and production of gas involves 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:

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unexpected drilling conditions;

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

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pressure or irregularities in formations;

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equipment failures or repairs;

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fires or other accidents;

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adverse weather conditions;

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water in the coal beds and nearby geological strata;

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pipeline ruptures or spills; and

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inadequate pipeline capacity to transport gas.

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.

CONSOL Energy must obtain governmental permits and approvals for mining and drilling operations, which can be a costly and time consuming process and which can 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, CONSOL Energy often is required to prepare and present to federal, state and local authorities data pertaining to the effect or impact that proposed exploration for or production of coal may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits CONSOL Energy needs 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 or gas operations or to do so profitably.

Competition within the coal and within the gas industry may adversely affect our ability to sell our products, or a loss of our competitive position because of overcapacity in these industries could adversely affect pricing which could impair our profitability.

CONSOL Energy competes with coal producers in various regions of the United States and with some foreign coal producers for domestic sales primarily to power generators. CONSOL Energy also competes with

both domestic and foreign coal producers for sales in international markets. Demand for our coal by our principal customers is affected by the delivered price of competing coals, other fuel supplies and alternative generating sources, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power. CONSOL Energy sells coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.

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. Recent increases in coal prices could encourage the development of expanded capacity by new or existing coal producers. Any resulting overcapacity could reduce coal prices and therefore reduce our revenues.

We compete against many gas producers who are larger and better financed than we are. If demand for gas falls or prices are lower, we may not be able to compete profitably against these larger competitors. For example, in 2002, gas prices were much lower than current prices because mild weather conditions reduced demand and led to oversupply of natural gas.

A significant extended decline in the prices CONSOL Energy receives for our coal and gas could adversely affect our operating results and cash flows.

CONSOL Energy’s results of operations are highly dependent upon the prices we receive for our coal and gas, which are closely linked to consumption patterns of the electric generation industry and certain industrial and residential patterns where gas is the principal fuel. Extended or substantial price declines for coal or gas would adversely affect our operating results for future periods and our ability to generate cash flows necessary to improve productivity and expand operations. We expect to be significantly less hedged for gas price fluctuations in 2006 than we have been in the past. Prices of coal and gas may fluctuate widely due to factors beyond our control such as overall domestic and global economic condition; the consumption pattern of industrial consumers, electricity generators and residential users; technological advances affecting energy consumption; domestic and foreign government regulations; price and availability of alternative fuels; price of foreign imports and weather conditions. For example, in 2002, demand for coal and natural gas decreased because of the warm winters in the northeastern United States. This resulted in increased inventories that caused prices to decrease.

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

CONSOL Energy 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. CONSOL Energy’s inability to satisfy contractual obligations could result in our customers initiating claims against us.

Unless we replace our natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2005, production is expected to decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. Thus, we may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

We may incur additional costs to produce gas because our chain of title work for gas rights in some of our properties may be inadequate or incomplete.

Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. We acquired these properties primarily for the coal rights, and, in many cases were acquired years ago. While chain of title work for the coal estate was generally fully developed, in many cases, the gas estate title work is less robust. Our practice is to review gas estate title work when we consider exploratory or production drilling and to obtain any additional rights needed to perfect our ownership for production purposes of the gas estate. In addition, the steps needed to perfect our ownership varies from state to state and some states permit us to produce the gas without perfected ownership under forced pooling arrangements while other states do not permit this. As a result, we may have to incur title costs and pay royalties to produce gas on acreage that we control and these costs may be material and vary depending upon the state in which we operate. In addition, although we believe we have the right to extract and produce coalbed methane (CBM) from locations where we possess rights to coal, in some cases we may not possess these rights. If we are unable in such cases to obtain those rights from their owners, we will not enjoy the rights to develop the CBM with our mining of coal as provided in the Master Cooperation and Safety Agreement. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserve. For example, we have substantial acreage in West Virginia for which we have not reviewed the title to determine what, if any, additional rights would be needed to produce CBM from those locations or the feasibility of obtaining those rights.

We need to use unproven technologies to extract coalbed methane on some of our properties.

Our ability to extract gas in coal seams with lower gas content per ton of coal such as the Pittsburgh #8 seam requires the use of advanced technologies that are still being developed and tested. Horizontal drilling is the advanced technology currently being used. This technique, applied in coal seams requires a well design that promotes simultaneous production of water and methane without significant back-pressure, a well that can be subsequently mined through without jeopardizing mine safety and a well that will ensure wellbore integrity throughout its projected life.

Currently the vast majority of our gas producing properties are located in two counties in southwestern Virginia, making us vulnerable to risks associated with having our gas production concentrated in one area.

The vast majority of our gas producing properties are geographically concentrated in two counties in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of gas production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area.

We do not insure against all potential operating risks. We may incur losses and be subject to liability claims as a result of our operations.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition, results of operations and cash flows.

Other persons could have ownership rights in our advanced gas extraction techniques which could force us to cease using those techniques or pay royalties.

Although we believe that we hold sufficient rights to all of our advanced gas extraction techniques, other persons could contest our rights and claim ownership of one or more of our advanced techniques for extracting coalbed methane. For example, a third party recently asserted that several of our drilling techniques infringed several patents held by that person. A successful challenge to one or more of our advanced extraction techniques could adversely impact our financial performance and results of operation. We might have to pay a royalty which would increase our production costs or cease using that technique which could raise our production costs or decrease our production of coalbed methane. In addition, we could incur substantial costs in defending patent infringement claims, obtaining patent licenses, engaging in interference and opposition proceedings or other challenges to our patent rights or intellectual property rights made by third parties or in bring such proceedings.

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

During the year ended December 31, 2005, approximately 91% of the coal CONSOL Energy produced was sold under long-term contracts (contracts with terms of one year or more). If a substantial portion of CONSOL Energy’s long-term contracts are modified or terminated or if force majeure are exercised, CONSOL Energy would be adversely affected if we are unable to replace the contracts or if new contracts were not at the same level of profitability. The profitability of our long-term coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, and includes our production costs and other factors. Price changes, if any, provided in long-term supply contracts are not intended to reflect our cost increases, and therefore increases in our costs may reduce our profit margins. In addition, in periods of declining market prices, provisions for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility. As a result, CONSOL Energy may not be able to obtain long-term agreements at favorable prices (compared to either market conditions, as they may change from time to time, or our cost structure) and long-term contracts may not contribute to our profitability.

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.

For the year ended December 31, 2005, we derived approximately 25% of our total revenues from sales to our three largest customers. At December 31, 2005, we had approximately 11 coal and gas supply agreements with these customers that expire at various times from 2006 to 2022. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be successful and those customers may not continue to purchase coal and gas from us under long-term coal supply agreements. If any one of these three customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially.

Our ability to collect payments from our customers could be impaired if their creditworthiness declines.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base has changed with deregulation as some utilities sold their power plants to their non-regulated affiliates or third parties. These new power plant owners may have credit ratings that are below investment grade. In addition, the creditworthiness of certain of our customers and trading counterparties has deteriorated over the last few years due to lower than anticipated demand for energy and volatility. If the creditworthiness of our customers declines significantly, our $125 million accounts receivable securitization program and our business could be adversely affected.

The characteristics of coal may make it difficult for coal users to comply with various environmental standards, which are continually under review by international, federal and state agencies, related to coal combustion. As a result, they may switch to other fuels, which would affect the volume of CONSOL Energy’s sales.

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

For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), 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 alternative fuel could materially affect us if we cannot offset the cost of sulfur removal by lowering the delivered costs of our higher sulfur coals on an energy equivalent basis.

Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases may require the installation of additional costly control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels. For example, in 2005 the Environmental Protection Agency proposed separate regulations to establish mercury emission limits nationwide and to reduce the interstate transport of fine particulate matter and ozone through reductions in sulfur dioxides and nitrogen oxides through the eastern United States. The Environmental Protection Agency continues to require reduction of nitrogen oxide emissions in 22 eastern states and the District of Columbia and will require reduction of particulate matter emissions over the next several years for areas that do not meet air quality standards for fine particulates. In addition, Congress and several states are now considering legislation to further control air emissions of multiple pollutants from electric generating facilities and other large emitters. These new and proposed reductions will make it more costly to operate coal-fired plants and could make coal a less attractive fuel alternative to the planning and building of utility power plants in the future. To the extent that any new or proposed requirements affect our customers, this could adversely affect our operations and results.

Also, numerous proposals have been made at the international, national and state levels that are intended to limit or capture emissions of greenhouse gases, such as carbon dioxide. If comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States or individual states, it could have the effect of restricting the use of coal. Other efforts to reduce emissions of greenhouse gases also may affect the use of fossil fuels, particularly coal, as an energy source.

Government laws, regulations and other legal requirements relating to protection of the environment and health as well as safety matters increase our costs of doing business for active operations, both coal and gas, 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 as well as 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, the installation of various safety equipment in our mines, 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, health or safety laws.

For example, the federal Clean Water Act and corresponding state laws affect coal mining operations by imposing restrictions on discharges into regulated waters or precluding mining that might impact regulated waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. New requirements under the Clean Water Act and corresponding state laws could cause us to incur significant additional costs that adversely affect our operating results or may prevent us from being able to mine portions of our reserves.

In addition, CONSOL Energy incurs 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 or the Superfund and similar state statutes and has been named as a potentially responsible party at Superfund sites in the past.

CONSOL Energy has 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. CONSOL Energy accrues 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. The amounts recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected.

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

Coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce gas in commercial quantities. The cost of water disposal may affect our profitability.

CONSOL Energy has obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, could result in CONSOL Energy being required to expense greater amounts than anticipated.

CONSOL Energy provides various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. At December 31, 2005, the current and non-current portions of these obligations included:

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post retirement medical and life insurance ($1.7 billion);

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coal workers’ black lung benefits ($423 million);

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salaried retirement benefits ($86 million); and

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workers’ compensation ($198 million).

However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. These obligations are unfunded, except for salaried retirement benefits, of which approximately 66%

was funded at December 31, 2005. In addition, several states in which we operate consider changes in workers’ compensation and black lung laws from time to time. Such changes, if enacted, could increase our benefit expense.

Due to our participation in multi-employer pension plans, we may have exposure under those plans that extend beyond what our obligation would be with respect to our employees.

We contribute to two multi-employer defined benefit pension plans administered by the UMWA. In the event of a partial or complete withdrawal by us from any plan which is underfunded, we would be liable for a proportionate share of such plan’s unfunded vested benefits. Based on the limited information available from plan administrators, which we cannot independently validate, we believe that our portion of the contingent liability in the case of a full withdrawal or termination could be material to our financial position and results of operations. In the event that any other contributing employer withdraws from any plan which is underfunded, and such employer (or any member in its controlled group) cannot satisfy their obligations under the plan at the time of withdrawal, then we, along with the other remaining contributing employers, would be liable for our proportionate share of such plan’s unfunded vested benefits.

In addition, if a multi-employer plan fails to satisfy the minimum funding requirements, the Internal Revenue Service, pursuant to Section 4971 of the Internal Revenue Code (the “Code”) will impose an excise tax of 5% on the amount of the accumulated funding deficiency. Under Section 413(c)(5) of the Code, the liability of each contributing employer, including us, will be determined in part by each employer’s additional contributions in order to reduce the deficiency to zero, which may, along with the payment of the excise tax, have a material adverse impact on our financial results.

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

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

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

One of CONSOL Energy’s subsidiaries, Fairmont Supply Company, which distributes industrial supplies, currently is named as a defendant in approximately 26,300 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, New Jersey, Michigan 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 our financial position, results of operations or cash flows of CONSOL Energy.

Various federal or state laws and regulations require CONSOL Energy 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.

Federal and state laws and regulations require us to obtain surety bonds or provide other assurances to secure payment of certain long-term obligations including mine closure or reclamation costs, water treatment costs, federal and state workers’ compensation costs, and other miscellaneous obligations. The requirements and amounts of security are not fixed and can vary from year to year. It has become increasingly difficult for us to secure new surety bonds or renew such bonds without posting collateral. CONSOL Energy has satisfied our obligations under these statutes and regulations by providing letters of credit or other assurances of payment. The issuance of letters of credit under our bank credit facility reduces amounts that we can borrow under our bank credit facility for other purposes.

CONSOL Energy’s rights plan may have anti-takeover effects that could prevent a change of control.

On December 19, 2003, CONSOL Energy adopted a rights plan which, in certain circumstances, including a person or group acquiring, or the commencement of a tender or exchange offer that would result in a person or group acquiring, beneficial ownership of more than 15% of the outstanding shares of CONSOL Energy common stock, would entitle each right holder to receive, upon exercise of the right, shares of CONSOL Energy common stock having a value equal to twice the right exercise price. For example, at an exercise price of $80 per right, each right not otherwise voided would entitle its holders to purchase $160 worth of shares of CONSOL Energy common stock for $80. Assuming that shares of CONSOL Energy common stock had a per share value of $16 at such time, the holder of each right would be entitled to purchase ten shares of CONSOL Energy common stock for $80, or a price of $8 per share, one half its then market price. This and other provisions of CONSOL Energy’s rights plan could make it more difficult for a third party to acquire CONSOL Energy, which could hinder stockholders’ ability to receive a premium for CONSOL Energy stock over the prevailing market prices.

Item 1B.

Unresolved Staff Comments.

None.

Item 2.

Properties.

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

Item 3.

Legal Proceedings.

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

One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 26,300 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, New Jersey and Mississippi. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the

pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time and, in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. During 2005 and 2004 payments by Fairmont with respect to asbestos cases have not been material. Our current estimates related to these asbestos claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of Consol Energy. However, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material to the financial position, results of operations or cash flows of CONSOL Energy.

CONSOL Energy is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes, and other claims and actions arising out of the normal course of business. Our current estimates related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of Consol Energy. However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations or cash flows of CONSOL Energy. In 1991, CONSOL Energy was named a potentially responsible party related to the Buckeye Landfill Superfund Site and accordingly recognized an estimated liability for remediation of this site of which $2,703 remained as of March 31, 2004. In April 2004, CONSOL Energy entered into an Environmental Liability Transfer and Indemnity Agreement that transferred our liability related to the Buckeye Landfill Superfund Site to another party. The transaction resulted in the reversal of the remaining liability and the recognition of $1,438 of income.

CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that we are a potentially responsible party (PRP) under Superfund legislation with respect to the Ward Transformer site in Wake County, North Carolina. At the time, the EPA also identified 38 other PRPs for the Ward Transformer site. On September 16, 2005, EPA, CONSOL Energy and three other PRPs entered into an Administrative Settlement Agreement and Order on Consent, requiring those PRPs to undertake and complete a PCB soil removal action, at and in the vicinity of the Ward Transformer property. In December 2005, EPA approved the PRPs’ work plan, and field work began the first week of January 2006. The current estimated undiscounted cost of the removal action including payment of EPA’s past and future costs, is approximately $7,000. CONSOL Energy’s interim allocation among the 4 participating PRPs is approximately 40%-45%. Accordingly, CONSOL Energy recognized a $3,000 liability, of which $1,500 was recognized in 2004 and $1,500 was recognized in 2005. This liability is included in Other Accrued Liabilities. The related cost is included in cost of goods sold and other charges. As of December 31, 2005, CONSOL Energy has made no payments to date related to the remediation of this site. CONSOL Energy and the other participating PRPs are investigating contribution claims against other, non-participating PRPs, and such claims may be brought to recover a share of the costs incurred. In addition, EPA has advised the PRPs that it is investigating additional areas of potential contamination allegedly related to the Ward Transformer site.

On October 21, 2003 a complaint was filed in the United States District Court for the Western District of Pennsylvania on behalf of Seth Moorhead against CONSOL Energy, J. Brett Harvey and William J. Lyons. The complaint alleges, among other things, that the defendants violated Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated under the Exchange Act and that during the period between January 24, 2002 and July 18, 2002 the defendants issued false and misleading statements to the public that failed to disclose or misrepresented the following, among other things that: (a) CONSOL utilized an aggressive approach regarding its spot market sales by reserving 20% of its production to that market, and that by increasing its exposure to the spot market, CONSOL Energy was subjecting itself to increased risk and uncertainty as the price and demand for coal could be volatile; (b) CONSOL Energy was experiencing difficulty selling the production that it had

allocated to the spot market, and, nonetheless, CONSOL Energy maintained its production levels which caused its coal inventory to increase; (c) CONSOL Energy’s increasing coal inventory was causing its expenses to rise dramatically, thereby weakening its financial condition; (d) CONSOL Energy’s production problems and costs there of were also weakening its financial condition, and (e) based on the foregoing, defendants’ positive statements regarding CONSOL Energy’s earnings and prospects were lacking in a reasonable basis at all times and therefore were materially false and misleading. The complaint asks the court to (1) award unspecified damages to plaintiff and (2) award plaintiff reasonable costs and expenses incurred in connection with this action, including counsel fees and expert fees. CONSOL Energy management believes these claims are without merit and have a remote chance of being awarded, accordingly, we have not accrued any liability associated with these claims.

Yukon Pocahontas Coal Company, Buchanan Coal Company, and Sayers-Pocahontas Coal Company filed an action on March 22, 2004 against us which is presently pending in the U.S. District Court for the Western District of Virginia. The action related to untreated water in connection with mining activities at our Buchanan Mine being deposited in the void spaces of nearby mines. The plaintiffs are seeking to stop us from depositing any additional water in these areas, to remove the water that is stored there along with any remaining impurities, to recover $300 million of compensatory and trebled damages and to recover punitive damages. We believe we had, and continue to have, the right to store water in these areas. We have denied liability and intend to vigorously defend this action; consequently, we have not recognized any liability related to this claim. Although we cannot currently estimate the impact of this claim, it is reasonably possible that payments in the future with respect to this pending claim may be material to the financial position, results of operations or cash flows of CONSOL Energy.

As previously disclosed, we expensed and paid approximately $28,000 to the Combined Fund for the plan year beginning October 1, 2003 related to a premium differential announced by the Social Security Administration for the past eleven plan years for beneficiaries assigned to CONSOL Energy. The premium differential is the difference between the lower premium rates determined by the National Coal Association v. Chater case and the higher premium rates determined by the Holland v. Barnhart case. Additionally, CONSOL Energy has expensed approximately $2,000 related to the premium differential for the plan year beginning October 1, 2004. In August 2005, a court ruling determined that the UMWA Health and Retirement Funds were illegally charging the premium differential. CONSOL Energy was also assessed an unassigned beneficiary premium increase of approximately $6,000 for the plan years beginning October 1, 2002 and October 1, 2003. We believe the calculation of the unassigned beneficiary premium is not accurate and, therefore, we have not paid this premium. CONSOL Energy has accrued an estimated liability related to this premium. The Combined Fund is protesting the court’s decision. If the courts rule in CONSOL Energy’s favor, the premium differential may be refunded to us and the unassigned beneficiary premium liability may be reduced. However, the legal process is lengthy and its outcome cannot be predicted with certainty. No estimates of refunds have been recorded and no amounts have been received from the UMWA Health and Retirement Funds to date.

Item 4.

Submission of Matters to a Vote of Security Holders.

None.

PART II

Item 5.

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

Common Stock Market Prices and Dividends

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


	High		Low		Dividends
Year Period Ended December 31, 2004
Quarter Ended March 31, 2004	$	30.01	$	20.24	$	0.14
Quarter Ended June 30, 2004	$	36.73	$	24.85	$	0.14
Quarter Ended September 30, 2004	$	39.25	$	29.80	$	0.14
Quarter Ended December 31, 2004	$	43.90	$	32.11	$	0.14
Year Period Ended December 31, 2005
Quarter Ended March 31, 2005	$	48.31	$	37.90	$	0.14
Quarter Ended June 30, 2005	$	54.15	$	41.97	$	0.14
Quarter Ended September 30, 2005	$	76.27	$	55.73	$	0.14
Quarter Ended December 31, 2005	$	79.03	$	54.12	$	0.14

As of February 7, 2006, there were approximately 66,000 holders of record of our common stock. The computation of the approximate number of shareholders is based upon a broker search.

On January 27, 2006, CONSOL Energy’s board of directors declared a dividend of $0.14 per share, payable on February 24, 2006, to shareholders of record on February 9, 2006.

The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s board of directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s board of directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, the credit ratings of CONSOL Energy, planned investments by CONSOL Energy and such other factors as the board of directors deems relevant. Current outstanding indebtedness of CONSOL Energy does not restrict our ability to pay cash dividends up to $0.56 per share per fiscal year, except that the credit facility would not permit dividend payments in the event of a default. The limitation on paying cash dividends up to $0.56 per share per fiscal year will not apply if the leverage ratio covenant is 1.00 to 1.00 or less. This ratio was 0.07 to 1.00 at December 31, 2005.

See Part III, Item 11. “Executive Compensation” for information relating to CONSOL Energy’s equity compensation plans.

Item 6.

Selected Financial Data.

The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the years ended December 31, 2005, 2004, 2003 and 2002 are derived from our audited consolidated financial statements. The selected consolidated financial data for, and as of the end of, the year ended December 31, 2001 are derived from our unaudited consolidated financial statements, and in the opinion of management include all adjustments, consisting only of normal recurring accruals, that are necessary for a fair presentation of our financial position and operating results for these periods. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and the financial statements and related notes included in this report. In 2001, we changed our fiscal year from a fiscal year ended June 30 to a fiscal year ended December 31 in order to coordinate reporting periods with our majority shareholder at that time commencing with the fiscal year started January 1, 2002.

STATEMENT OF INCOME DATA

(In thousands except per share data)


	Year Ended December 31,
	2005			2004			2003			2002			2001
													(Unaudited)
Revenue and Other Income:
Sales—Outside and Related Party	$	2,982,582		$	2,468,248		$	2,042,851		$	2,003,345		$	2,095,463
Sales—Purchased Gas		275,148			112,005			—			—			—
Freight—Outside and Related Party(A)		119,811			110,175			114,582			134,416			159,029
Other income		105,582			86,321			65,033			45,837			64,526
Gain on Sale of 18.5% interest in CNX Gas		327,326			—			—			—			—

Total Revenue and Other Income		3,810,449			2,776,749			2,222,466			2,183,598			2,319,018
Costs:
Cost of goods sold and other operating charges (exclusive of depreciation, depletion and amortization shown below)		2,158,760			1,887,947			1,624,016			1,543,189			1,585,686
Purchased gas costs		278,720			113,063			—			—			—
Freight expense		119,811			110,175			114,582			134,416			159,029
Selling, general and administrative expense		80,700			72,870			77,571			65,888			61,155
Depreciation, depletion and amortization		261,851			280,397			242,152			262,873			243,588
Interest expense		27,317			31,429			34,451			46,213			43,356
Taxes other than income		228,606			198,305			160,209			172,479			160,954
Export sales excise tax resolution		—			—			(614	)		(1,037	)		(118,120	)
Restructuring costs		—			—			3,606			—			—

Total Costs		3,155,765			2,694,186			2,255,973			2,224,021			2,135,648

Earnings (loss) before income taxes, minority interest and cumulative effect of change in accounting principle		654,684			82,563			(33,507	)		(40,423	)		183,370
Income taxes (benefits)		64,339			(32,646	)		(20,941	)		(52,099	)		32,164

Earnings (loss) before minority interest and cumulative effect of change in accounting principle		590,345			115,209			(12,566	)		11,676			151,206
Minority interest		(9,484	)		—			—			—			—
Cumulative effect of changes in accounting for workers’ compensation liability, net of income taxes of $53,080		—			83,373			—			—			—
Cumulative effect of changes in accounting for mine closing, reclamation and gas well closing costs, net of income taxes of $3,035		—			—			4,768			—			—

Net Income (loss)	$	580,861		$	198,582		$	(7,798	)	$	11,676		$	151,206

Earnings per share from continuing operations
Basic	$	6.33		$	1.28		$	(0.15	)	$	0.15		$	1.92

Dilutive	$	6.26		$	1.26		$	(0.15	)	$	0.15		$	1.91

Earnings per share from net income
Basic(B)	$	6.33		$	2.20		$	(0.10	)	$	0.15		$	1.92

Dilutive(B)	$	6.26		$	2.18		$	(0.10	)	$	0.15		$	1.91

Weighted average number of common shares outstanding:
Basic		91,744,954			90,230,693			81,732,589			78,728,560			78,671,821

Dilutive		92,767,490			91,199,945			81,732,589			78,834,023			78,964,557

Dividend per share	$	0.56		$	0.56		$	0.56		$	0.84		$	1.12

BALANCE SHEET DATA

(In thousands)


	At December 31,
	2005		2004			2003			2002			2001
Working capital (deficiency)	$	194,578	$	(243,275	)	$	(358,459	)	$	(191,596	)	$	(70,505	)
Total assets		5,087,652		4,195,611			4,318,978			4,293,160			4,298,732
Short-term debt		—		5,060			68,760			204,545			77,869
Long-term debt (including current portion)		442,996		429,645			495,242			497,046			545,440
Total deferred credits and other liabilities		2,726,563		2,582,318			2,757,130			2,828,249			2,913,763
Stockholders’ equity		1,025,356		469,021			290,637			162,047			271,559

OTHER OPERATING DATA

(Unaudited)


	Year Ended December 31,
	2005		2004		2003		2002		2001
Coal:
Tons sold (in thousands)(C) (D)		70,537		69,537		63,962		67,308		76,503
Tons produced (in thousands)(D)		69,126		67,745		60,388		66,230		73,705
Productivity (tons per manday)(D)		37.95		40.51		41.26		40.18		39.95
Average production cost ($ per ton produced)(D)	$	30.06	$	27.54	$	26.24	$	24.73	$	22.21
Average sales price of tons produced ($ per ton produced)(D)	$	35.61	$	30.06	$	27.61	$	26.76	$	24.66
Recoverable coal reserves (tons in millions)(D)(E)		4,546		4,509		4,158		4,275		4,365
Number of active mining complexes (at period end)		17		16		15		17		21
Gas:
Net sales volume produced (in billion cubic feet) (D)		48.39		48.56		44.46		41.30		33.92
Average sale price ($ per mcf)(D)(F)	$	6.72	$	5.41	$	4.31	$	3.17	$	4.04
Average costs ($ per mcf) (D)	$	2.69	$	2.45	$	2.35	$	2.18	$	2.38
Proved reserves (in billion cubic feet)(D)(G)		1,130		1,045		1,004		961		1,023

CASH FLOW STATEMENT DATA

(In thousands)


	Year Ended December 31,
	2005			2004			2003			2002			2001
Net cash provided by operating activities	$	409,086		$	358,091		$	381,127		$	329,556		$	347,356
Net cash used in investing activities		(74,413	)		(400,542	)		(204,614	)		(339,936	)		(114,160	)
Net cash (used in) provided by financing activities		(455	)		42,360			(181,517	)		6,315			(228,184	)

OTHER FINANCIAL DATA

(Unaudited)

(In thousands)


Capital expenditures	$	523,467	$	410,611	$	290,652		$	295,025		$	266,825
EBIT(H)		664,451		108,616		(5,354	)		(1,230	)		194,330
EBITDA(H)		926,302		389,013		236,798			261,643			437,918
Ratio of earnings to fixed charges(I)		15.95		2.76		—			—			4.38

(A)	See Note 28 of Notes to Consolidated Financial Statements for sales and freight by operating segment.

(B)

Basic earnings per share are computed using weighted average shares outstanding. Differences in the weighted average number of shares outstanding for purposes of computing dilutive earnings per share are due to the inclusion of the weighted average dilutive effect of employee and non-employee director stock options granted, totaling 1,022,536, 969,252, none, 105,463 and 292,736 for the year ended December 31, 2005, 2004, 2003, 2002 and 2001.

(C)

Includes sales of coal produced by CONSOL Energy and purchased from third parties. Of the tons sold, CONSOL Energy purchased the following amount from third parties: 1.6 million tons in year ended December 31, 2005; 2.1 million tons in the year ended December 31, 2004; 2.5 million tons in the year ended December 31, 2003; 2.5 million tons in the year ended December 31, 2002 and 2.8 million tons in the year ended December 31, 2001. There were no sales of coal produced by equity affiliates in the year ended December 31, 2005. Sales of coal produced by equity affiliates in previous periods were: 0.1 million tons in the year ended December 31, 2004; 1.0 million tons in the year ended December 31, 2003; 1.6 million tons in the year ended December 31, 2002; and 1.6 million tons in the year ended December 31, 2001.

(D)

Amounts include intersegment transactions. For entities that are not wholly owned but in which CONSOL Energy owns at least 50% equity interest, includes a percentage of their net production, sales or reserves equal to CONSOL Energy’s percentage equity ownership. For coal, Glennies Creek Mine is reported as an equity affiliate through February 2004. Glennies Creek Mine is reported as an equity affiliate for the entire December 2003 period and Line Creek was reported as an equity affiliate through February 2003. Line Creek Mine and Glennies Creek Mine are reported as equity affiliates for the December 31, 2002 period. Line Creek Mine was also reported as an equity affiliate for the December 31, 2001 period. For gas, Knox Energy makes up the equity earnings data in 2005, 2004, 2003 and 2002. Greene Energy was part of equity earnings in 2002 and 2001. Pocahontas Gas Partnership accounts for the majority of the information reported as an equity affiliate for approximately eight months in the December 31, 2001 period. Sales of gas produced by equity affiliates were 0.23 bcf in the year ended December 31, 2005, 0.20 bcf in the year ended December 31, 2004, .08 bcf in the year ended December 31, 2003, .22 bcf in the year ended December 31, 2002 and 5.5 bcf in the year ended December 31, 2001.

(E)	Represents proven and probable coal reserves at period end.

(F)	Represents average net sales price before the effect of derivative transactions.

(G)	Represents proved developed and undeveloped gas reserves at period end.

(H)

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


	Year Ended December 31,
(Unaudited) (In thousands)	2005			2004			2003			2002			2001
													(Unaudited)
Net Income (Loss)	$	580,861		$	198,582		$	(7,798	)	$	11,676		$	151,206
Add: Interest expense		27,317			31,429			34,451			46,213			43,356
*Less: Interest income		(8,066	)		(5,376	)		(5,602	)		(5,738	)		(5,990	)
*Less: Interest income included in export sales excise tax resolution		—			—			(696	)		(1,282	)		(26,406	)
Less: Cumulative Effect of Changes in Accounting for Workers’ Compensation Liability, net of Income Taxes of $53,080		—			(83,373	)		—			—			—
Less: Cumulative Effect of Changes in Accounting for Mine Closing, Reclamation and Gas Well Closing Costs, net of Income taxes of $3,035		—			—			(4,768	)		—			—
Add: Income Tax Expense (Benefit)		64,339			(32,646	)		(20,941	)		(52,099	)		32,164

Earnings (Loss) before interest and taxes (EBIT)		664,451			108,616			(5,354	)		(1,230	)		194,330
Add: Depreciation, depletion and amortization		261,851			280,397			242,152			262,873			243,588

Earnings before interest, taxes and depreciation, depletion and amortization (EBITDA)	$	926,302		$	389,013		$	236,798		$	261,643		$	437,918

(I)

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

Item 7.

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

General

CONSOL Energy had net income of $581 million for the year ended December 31, 2005 compared to $199 million for the year ended December 31, 2004. Net income for the 2005 period was improved due to the $327 million gain on sale of 18.5% interest in CNX Gas Corporation. On June 21, 2005, the Board of Directors of CONSOL Energy authorized the incorporation of CNX Gas Corporation (CNX Gas). On June 30, CNX Gas was incorporated and issued 100 shares of its $0.01 par value common stock to Consolidation Coal Company, a wholly-owned subsidiary of CONSOL Energy. CNX Gas was incorporated to conduct CONSOL Energy’s gas exploration and production activities. In August 2005, CONSOL Energy contributed or leased substantially all of the assets of its gas business, including all of CONSOL Energy’s rights to coalbed methane associated with 4.5 billion tons of coal reserves owned or controlled by CONSOL Energy as well as all of CONSOL Energy’s rights to conventional gas. In exchange for CONSOL Energy’s contribution of assets, CONSOL Energy received approximately 122.9 million shares of CNX Gas common stock. CNX Gas entered into various agreements with CONSOL Energy that define various operating and service relationships between the two companies. In August 2005, CNX Gas entered into an agreement to sell approximately 24.3 million shares in a private transaction and granted a 30-day option to purchase an additional 3.6 million shares. In August 2005, CNX Gas closed on the sale of all 27.9 million shares. The shares were sold to qualified institutional, foreign and accredited investors in a private transaction exempt from registration under Rule 144A, Regulation S and Regulation D. In August 2005, a Registration Statement on Form S-1 was filed with the SEC with respect to those shares. The registration statement was declared effective on January 18, 2006. The proceeds (approximately $420,167 including proceeds from the sale of the additional 3.6 million shares) were used to pay a special dividend to CONSOL Energy. The gain recognized on this transaction was $327,326. The proceeds received less the financial basis in the assets and liabilities given up were recognized as a gain on sale of a subsidiary’s stock in the year ended December 31, 2005 in the consolidated financial statements. In accordance with Statement of Financial Accounting Standards Board Statement No. 109, “Accounting for Income Taxes”, no deferred tax was provided on this transaction as current tax law provides a means by which the excess of the reported amount of this investment over its tax basis can be recovered tax-free. Also, management has no current intention of entering into a transaction that would cause CNX Gas to leave the consolidated tax group. Improved net income was also due to higher average sales prices for coal and gas. This increase was offset, in part by costs related to the Buchanan Mine fire and by higher cost per units sold for both coal and gas. Higher coal unit costs were primarily due to higher supply costs, higher labor costs, higher contract mining fee costs and higher other post employment benefits per unit sold. Higher gas unit costs were primarily attributable to increased royalty expense, changes in imbalance amounts and firm transportation costs. Net income in the 2004 period included $83 million due to a cumulative effect of change in accounting for workers’ compensation.

Total coal sales for the year ended December 31, 2005 were 70.5 million tons, including sales by consolidated variable interest entities, of which 68.9 million tons were produced by CONSOL Energy operations, or sold from inventory of company-produced coal. This compares with total coal sales of 69.5 million tons for the year ended December 31, 2004, of which 67.4 million tons were produced by CONSOL Energy operations or sold from inventory of company-produced coal. Overall, production of 69.1 million tons, including production from consolidated variable interest entities and our portion of equity affiliates, increased 1.4 million tons from the 2004 period. Bailey Mine, McElroy Mine, Loveridge Mine and Emery Mine set production records in 2005, which offset the estimated loss of approximately 2.5 million tons from the Buchanan Mine due to problems that occurred there during the year.

Sales volumes of coalbed methane gas, including a percentage of the sales of equity affiliates equal to our interest in these affiliates, decreased 0.9% to 55.0 billion cubic feet for the year ended December 31, 2005 compared with 55.5 billion cubic feet in the year ended December 31, 2004. The decrease in sales volumes is primarily due to the loss of 3.6 billion cubic feet related to the Buchanan fire and 1.1 billion cubic feet from curtailments on shipment capacity on the Columbia interstate pipeline. Our average sales price for coalbed methane gas, including sales of equity affiliates increased 19.2% to $6.02 per thousand cubic feet in the 2005 period compared with $5.05 per thousand cubic feet in the 2004 period.

In September 2005, the Buchanan Mine, near Keen Mountain, Virginia, suspended production following a problem with the mine’s skip hoist mechanism. The hoist was repaired and production resumed on December 13, 2005. It is estimated that the mine lost approximately 1.0 million tons of production during the period that production was suspended. During that period, the company invoked the force majeure provision on all sales contracts for Buchanan Mine coal.

In October 2005, David C. Hardesty, President-West Virginia University, was elected to the CONSOL Energy Board of Directors.

In December 2005, the Board of Directors authorized a common share repurchase program of up to $300 million during the 24-month period beginning January 1, 2006 and ended December 31, 2007. CONSOL has repurchased 155,000 shares through February 7, 2006 at an average price of $69.06 under this program.

In January 2006, CONSOL Energy entered into a coal sales agreement with American Electric Power (AEP) for the sale of up to 82.5 million tons of high-Btu bituminous coal to various AEP coal-fired power stations over a 15-year period beginning in 2007 and running through 2021. The coal will come from the Shoemaker and McElroy mines and will be shipped to AEP power plants that have or will be equipped to have scrubbers. As a result of the new contract, we will begin a major capital improvement project for the Shoemaker Mine, replacing the mine’s older, rail haulage system with a new, more efficient conveyor belt haulage system.

In January 2006, CONSOL Energy purchased Mon River Towing and J.A.R. Barge Lines, LP from the Guttman Group, a private concern. The acquisition will increase the size of CONSOL Energy’s towboat fleet from 5 to 18 and increase the number of barges from about 300 to more than 650, increasing coal transportation capacity from 11 million tons to about 24 million tons. The transaction closed on January 20, 2006.

Over the next two years, electricity generation in the United States is forecast to grow approximately 2.0% per annum, absent any adverse weather impacts. According to industry reports, coal inventories are significantly below normal in the United States and could add 10-20 million tons of demand in 2006. Furthermore, natural gas prices remain high and make gas powered generation more expensive than that of coal. These factors should contribute to an already tight supply/demand balance for U.S. thermal (steam) coal.

The United States Energy Information Administration (EIA) has forecasted that over the next four years there are more than 12 gigawatts of planned capacity additions from new generators that will use coal as an energy source—requiring an estimated 30 million tons of high-Btu coal per year. In addition, there are nearly 50 gigawatts of existing coal-fired power scheduled to be retrofitted with scrubbers over the same time frame. CONSOL Energy expects to benefit from: the long-term demand for high-Btu Northern Appalachia coal due to new and retrofitted scrubbers on power plants geographically located near CONSOL’s mines; the growing demand for electricity generation as consumers use more electricity-dependent devices; the geological limitations of Central Appalachian coal; and the potential transportation issues associated with lower Btu coal.

While the overall market for coal remains positive, we believe the growth in demand for Northern Appalachian coal will exceed the industry’s organic growth by a wide-margin. The transaction with AEP that we announced earlier this month is indicative of the way we see this market evolving. Major coal-burning power generators are beginning to move to the high-Btu products available close to their plants as their scrubber construction projects are completed.

Results of Operations

Twelve Months Ended December 31, 2005 Compared with Twelve Months Ended December 31, 2004

Net Income

Net income changed primarily due to the following items (table in millions):


	2005			2004			Dollar Variance			Percentage Change
Coal Sales—Produced and Purchased (Outside and Related Party)	$	2,527		$	2,087		$	440		21.1	%
Produced Gas Sales		327			275			52		18.9	%
Purchased Gas Sales		275			112			163		145.5	%
Gain on Sale of 18.5% interest in CNX Gas		327			—			327		100.0	%
Other Sales and Other Income		354			303			51		16.8	%

Total Revenue and Other Income		3,810			2,777			1,033		37.2	%
Coal Cost of Goods Sold—Produced and Purchased		1,702			1,533			169		11.0	%
Produced Gas Cost of Goods Sold		116			105			11		10.5	%
Purchased Gas Cost of Goods Sold		279			113			166		146.9	%
Other Cost of Goods Sold		340			250			90		36.0	%

Total Cost of Goods Sold		2,437			2,001			436		21.8	%

Other		719			693			26		3.8	%

Total Costs		3,156			2,694			462		17.1	%

Earnings Before Income Taxes, Minority Interest and Cumulative Effect of Change in Accounting		654			83			571		688.0	%
Income Tax Expense (Benefit)		64			(33	)		97		293.9	%

Earnings Before Minority Interest and Cumulative Effect of Change in Accounting Principle		590			116			474		408.6	%
Minority Interest		(9	)		—			(9	)	(100.0	)%

Earnings Before Cumulative Effect of Change in Accounting Principle		581			116			465		400.9	%
Cumulative Effect of Change in Accounting Principle		—			83			(83	)	(100.0	)%

Net Income	$	581		$	199		$	382		192.0	%

Earnings before cumulative effect of change in accounting for the 2005 period were improved primarily due to the gain on sale of 18.5% interest in CNX Gas. In August 2005, CNX Gas, a subsidiary of CONSOL Energy, sold 27.9 million shares in a private transaction. CNX Gas received proceeds of $420.2 million, which it used to pay a special dividend to CONSOL Energy. The proceeds received less the financial basis in the assets and liabilities given up by CONSOL Energy was recognized as a gain on sale of a subsidiary’s stock in the year ended December 31, 2005. The pre-tax gain recognized on this transaction was $327.3 million. In accordance with Statement of Financial Accounting Standards Board No. 109, “Accounting for Income Taxes”, no deferred tax has been provided on this transaction as current tax law provides a means by which the excess of the reported amount of this investment over its tax basis can be recovered tax-free. Also, management has no current intention of entering into a transaction that would cause CNX Gas to leave the consolidated tax group. Earnings before cumulative effect of change in accounting were also improved due to increased average sales prices for both coal and gas and increased volume of produced coal sold. These increases were offset, in part, by costs related to the Buchanan Mine fire and by higher cost per units sold for both coal and gas. Higher coal unit costs were primarily due to increased supply costs, higher labor costs, higher contractor mining fees and higher other post-employment benefits. Higher gas unit costs were primarily due to increased royalty expense, imbalance charges and firm transportation expenses. Net income in the 2004 period included a cumulative effect of change in

accounting related to workers’ compensation. Effective January 1, 2004, CONSOL Energy changed our method of accounting for workers’ compensation. Prior to the change, CONSOL Energy recorded our workers’ compensation liability on an undiscounted basis. Under the new method, CONSOL Energy records our liability on a discounted basis.

Revenue

Revenue and other income increased due to the following items:


	2005		2004		Dollar Variance		Percentage Change
Sales
Produced Coal—Outside and Related Party	$	2,448	$	2,008	$	440	21.9	%
Purchased Coal		79		79		—	—	%
Produced Gas		327		275		52	18.9	%
Purchased Gas		275		112		163	145.5	%
Industrial Supplies		93		79		14	17.7	%
Other		36		27		9	33.3	%

Total Sales		3,258		2,580		678	26.3	%
Freight Revenue		120		110		10	9.1	%
Gain on Sale of 18.5% of CNX Gas		327		—		327	100.0	%
Other Income		105		87		18	20.7	%

Total Revenue and Other Income	$	3,810	$	2,777	$	1,033	37.2	%

The increase in company produced coal sales revenue, including related party, during the 2005 period was due mainly to the increase in average sales price per ton and increased sales volumes.


	2005		2004		Variance		Percentage Change
Produced Tons Sold (in millions)		68.9		67.3		1.6	2.4	%
Average Sales Price Per Ton	$	35.54	$	29.84	$	5.70	19.1	%

The increase in average sales price primarily reflects stronger prices negotiated in 2004 and early 2005 resulting from an overall improvement in prices in the eastern coal market for domestic and foreign power generators and steel producers. The increase was also attributable to pricing premiums due to improved quality on coal shipments. The increase in tons sold was due primarily to increased production at McElroy, Loveridge, Bailey, the reactivation of Emery Mine in August 2004 and the opening of the Miller Creek complex in October 2004. These production increases were offset, in part, by a decrease in tons sold due to lower production at Buchanan and various contractor locations. The McElroy production increase is related to running two longwall mining units in the 2005 period compared to running one longwall mining unit in the 2004 period. The Loveridge production increase is due to the mine operating for the full twelve months of the 2005 period compared to only a portion of the 2004 period due to the fire at this location in 2003. Bailey production increases were due to increased productivity in the period-to-period comparison. Buchanan production decreased in the 2005 period due to a fire that developed in the mine after a large rock fall behind the longwall mining section on February 14, 2005. The mine was temporarily sealed in order to extinguish the fire. Buchanan resumed production on June 16, 2005. On September 16, 2005, Buchanan experienced an accident with the skip hoist which brings the coal from underground to the surface. The mine was idled until repairs to the skip hoist were completed. The mine resumed production on December 13, 2005.

Company-purchased coal sales revenue remained consistent in the period-to-period comparison due to an increase in average sales price per ton of purchased coal, offset by reduced sales volumes.


	2005		2004		Variance			Percentage Change
Produced Tons Sold (in millions)		1.6		2.1		(0.5	)	(23.8	)%
Average Sales Price Per Ton	$	48.41	$	37.60	$	10.81		28.8	%

The increased average sales price is primarily due to sales of purchased coal tons being sold in higher priced export and metallurgical markets. Increased revenue from higher average sales prices were offset by lower sales volumes of purchased coal in the 2005 period compared to the 2004 period.

The increase in gas sales revenue was due to a higher average sales price per thousand cubic feet sold in the 2005 period compared to the 2004 period.


	2005		2004		Variance			Percentage Change
Produced Gas Sales Volumes (in billion gross cubic feet)		54.4		54.6		(0.2	)	(0.4	)%
Average Sales Price per thousand cubic feet (including effects of derivative transactions)	$	6.00	$	5.04	$	0.96		19.0	%

We believe the 2005 gas market price increases were largely driven by continued concerns over levels of North American gas production, as well as increased oil prices and favorable economic conditions in the United States that encourage demand for natural gas. The adverse affect of the 2005 hurricane season also shut-in significant portions of Gulf Coast gas, increasing the tight supply, and leading to even higher prices in 2005. CONSOL Energy enters into various physical gas swap transactions with both gas marketers and other counterparties for terms varying in length. CONSOL Energy has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. These physical and financial hedges represented approximately 70% of our produced gas sales volumes for the year ended December 31, 2005 at an average price of $4.77 per thousand cubic feet. Despite the loss of approximately 4.0 billion cubic feet of gas related to the Buchanan Mine incident and 1.4 billion cubic feet due to maintenance related capacity constraints on CONSOL Energy’s transportation capacity on the Columbia interstate pipeline, sales volumes are only slightly lower in the 2005 period compared to the 2004 period. We were able to offset these production losses with additional volumes coming on-line from our on-going drilling program, and by successfully initiating a frac well enhancement and stimulation program on wells unaffected by the mine fire.

As a result of increased demand for pipeline use on the Columbia interstate pipeline, and the potential for curtailment on portions of the shipment capacity allocated to CONSOL Energy, we purchased firm transportation capacity on the pipeline during 2005. This arrangement offset a portion of the expected impact from periodic curtailments. In April 2005, we were given notice by Columbia regarding reductions in allowable gas flow due to routine maintenance and construction activities. Interruptible gas was completely shut-in and our contracted firm transportation flows were reduced by 60% which resulted in reduced revenues of $6.8 million along with other smaller curtailments throughout the year that were also eventually lifted. Although we anticipate that these pipeline constraints will be an on-going issue for the foreseeable future, we also intend to gain access to the East Tennessee Natural Gas (“ETNG”) pipeline, which is south of our Central Appalachia operations. ETNG has received the approval of the Federal Energy Regulatory Commission (“FERC”) for the construction of a 32-mile lateral pipeline, called Jewell Ridge Lateral, that will transport gas from our Central Appalachia operations to ETNG’s major transportation pipeline to the south. The FERC approval is subject to certain conditions, which ETNG is working to satisfy. Jewell Ridge Lateral is expected to be in service in the summer of 2006 and will provide us with an alternative transportation route to the northeast markets we currently serve as well as access to east coast markets.

Additionally, we simultaneously purchased gas from and sold gas to other counterparties between the segmentation and interruptible pools on the Columbia interstate pipeline in order to satisfy obligations to certain customers. In accordance with Emerging Issues Task Force 99-19, we have increased our revenues and our costs. Sales of purchased gas volumes have increased primarily due to CONSOL Energy utilizing higher levels of firm transportation throughout the 2005 period that required us to purchase from and sell to other counterparties. CONSOL Energy began to enter into this type of transaction in May of 2004.


	2005		2004		Variance		Percentage Change
Purchased Gas Sales Volumes (in billion gross cubic feet)		28.7		17.5		11.2	64.0	%
Average Sales Price per thousand cubic feet	$	9.59	$	6.39	$	3.20	50.1	%

The $14 million increase in revenues from the sale of industrial supplies was primarily due to increased sales volumes.

The $9 million increase in other sales was attributable to revenues from river barge towing. Under the Jones Act Bowater exemption, because CONSOL Energy was more than 25% owned by a foreign company, we were prohibited from providing river barge towing to third parties. CONSOL Energy began third party river barge towing shortly after RWE AG divested their ownership interest in the 2004 period as we were no longer restricted by the Jones Act.

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

On June 21, 2005, the Board of Directors of CONSOL Energy authorized the incorporation of CNX Gas Corporation (CNX Gas). On June 30, CNX Gas was incorporated and issued 100 shares of its $0.01 par value common stock to Consolidation Coal Company, a wholly-owned subsidiary of CONSOL Energy. CNX Gas was incorporated to conduct CONSOL Energy’s gas exploration and production activities. In August 2005, CONSOL Energy contributed or leased substantially all of the assets of its gas business, including all of CONSOL Energy’s rights to coalbed methane associated with 4.5 billion tons of coal reserves owned or controlled by CONSOL Energy as well as all of CONSOL Energy’s rights to conventional gas. In exchange for CONSOL Energy’s contribution of assets, CONSOL Energy received approximately 122.9 million shares of CNX Gas common stock. CNX Gas entered into various agreements with CONSOL Energy that define various operating and service relationships between the two companies. In August 2005, CNX Gas entered into an agreement to sell approximately 24.3 million shares in a private transaction and granted a 30-day option to purchase an additional 3.6 million shares. In August 2005, CNX Gas closed on the sale of all 27.9 million shares. The shares were sold to qualified institutional, foreign and accredited investors in a private transaction exempt from registration under Rule 144A, Regulation S and Regulation D. In August 2005, a Registration Statement on Form S-1 was filed with the SEC with respect to those shares. The registration statement was declared effective on January 18, 2006. The proceeds (approximately $420,167 including proceeds from the sale of the additional 3.6 million shares) were used to pay a special dividend to CONSOL Energy. The gain recognized on this transaction was $327,326.

Other income 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.


	2005		2004			Dollar Variance			Percentage Change
Royalty Income	$	26	$	19		$	7		$	36.8	%
Buchanan fire business interruption proceeds		18		—			18			100.0	%
Gain on sale of assets		15		41			(26	)		(63.4	)%
Interest Income		8		5			3			60.0	%
Harmar Trust Settlement		7		—			7			100.0	%
Equity in income (loss) of affiliates		3		(4	)		7			175.0	%
Other miscellaneous		28		26			2			7.7	%

Total Other Income	$	105	$	87		$	18			20.7	%

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

Buchanan Mine experienced a fire that developed in the mine after a large rock fall behind our longwall mining section on February 14, 2005. The mine was temporarily sealed in order to extinguish the fire. Coal production resumed on June 16, 2005. CONSOL Energy filed an insurance claim for reimbursement of various costs and business interruption related to the fire at Buchanan Mine. During the three months ended December 31, 2005, CONSOL Energy received an advance on the filed claim from the insurance companies. The portion of the advance related to fire abatement and various related costs relieved the previously established receivable. The portion related to business interruption was recognized as other income in the period received.

The decrease in gain on sale of assets in the 2005 period reflects CONSOL Energy’s sale of stock in our wholly owned subsidiary CNX Australia Pty Limited to certain affiliates of AMCI, Inc. for $27.5 million, the assumption of approximately $21.3 million of debt, and associated interest rate swaps and foreign currency hedges in the 2004 period. The sale resulted in a pre-tax gain of approximately $14.4 million. The additional gain on sale of assets in the 2004 period is primarily related to the sale of several previously closed operations. The 2005 period gain on sale of assets is primarily related to the sale of several previously closed operations.

Interest income increased in the period-to-period comparison due to our improved cash position. Cash and cash equivalent balances at December 31, 2005 were $340.6 million compared to $6.4 million at December 31, 2004. The improved cash position was primarily due to the August sale of 18.5% interest in CNX Gas stock. The private sale of this stock resulted in $420.2 million of proceeds.

Other income from the Harmar Environmental Trust (the Trust) Settlement was attributable to the Civil Division of the Court of Common Pleas of Allegheny County’s decision to terminate a Trust among CONSOL Energy and other parties. The Trust was established in 1988 to provide funding for water treatment related to the now closed Harmar Mine. Other parties funded the trust. CONSOL Energy was responsible to complete water treatment activities, but all costs associated with these activities were funded by the Trust Agreement. Any excess funding upon completion of water treatment or a specified date in the future was to be distributed to parties that originally funded the trust. In the decision, all previously funded, but unused, amounts remaining in the Trust were distributed. CONSOL Energy’s portion of the distributed funds, $15.0 million, was placed into an escrow account pending provision of financial assurance supporting CONSOL Energy’s water treatment obligations. CONSOL Energy provided the financial assurance for this obligation and the funds were released from escrow. CONSOL Energy is responsible for the ongoing water treatment at this facility. CONSOL Energy recorded the funds and the present value of the water treatment liability resulting in $6.5 million of income in the 2005 period.

The equity income of affiliates in the 2005 period is attributable to CONSOL Energy’s portion of a gain on sale of land by an affiliate. The equity losses of affiliates in the 2004 period is due mainly to the equity losses related to Glennies Creek Mine operating results prior to the sale that occurred in February 2004.

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

Costs


	2005		2004		Dollar Variance			Percentage Change
Cost of Good Sold and Other Charges
Produced Coal	$	1,613	$	1,457	$	156		10.7	%
Purchased Coal		89		76		13		17.1	%
Produced Gas		116		105		11		10.5	%
Purchased Gas		279		113		166		146.9	%
Industrial Supplies		105		94		11		11.7	%
Closed and Idle Mines		69		72		(3	)	(4.2	)%
Other		166		84		82		97.6	%

Total Cost of Goods Sold	$	2,437	$	2,001	$	436		21.8	%

Increased cost of goods sold and other charges for company-produced coal was due mainly to an 8.2% increase in cost per ton of produced coal sold and a 2.4% increase in sales volumes.


	2005		2004		Variance		Percentage Change
Produced Tons Sold (in millions)		68.9		67.3		1.6	2.4	%
Average Cost of Goods Sold and Other Charges Per Ton	$	23.42	$	21.64	$	1.78	8.2	%

Average cost of goods sold and other charges for produced coal increased due mainly to increased unit costs. This increase is attributable to higher supply costs, higher labor costs, higher contract mining fee costs and higher other post employment benefits per unit sold. Higher supply costs were attributable to increased maintenance costs and increased cost for steel, petroleum products and chemicals, such as magnetite, used in the mining and coal preparation process. Higher supply costs were also related to certain locations being in difficult mining conditions which increase costs on a per unit of output basis. Increased labor costs were attributable to increased employee counts and increased wages at certain mining operations. Mancounts have been increased in certain locations to maintain development rates ahead of the longwall mining units. Labor rates were increased in order to stay competitive in certain labor markets. Increased contract mining fees were attributable to increased fees negotiated with the contractors used primarily in our central Appalachian operations. Increased other post employment benefits were primarily due to the impact of cost increases for medical and drug benefits. Increased produced coal costs of goods sold was also due to higher sales volumes in the 2005 period compared to the 2004 period. These increases in costs were offset, in part, by reduced Combined Fund premiums related to a premium differential that was paid in the 2004 period. Also, CONSOL Energy currently anticipates that the 1992 Fund premiums will increase approximately $4 million for the plan year beginning January 1, 2006. Due to the recent insured losses at our mines, property and business interruption insurance coverage may be difficult to renew at the current pricing levels and terms.

Purchased coal cost of goods sold and other charges increased in the period-to-period comparison.


	2005		2004		Variance			Percentage Change
Purchased Tons Sold (in millions)		1.6		2.1		(0.5	)	(23.8	)%
Average Cost of Goods Sold and Other Charges Per Ton	$	54.34	$	36.34	$	18.00		49.5	%

The higher average cost of purchased coal is primarily due to overall increases in prices for domestic coals, offset by reduced volumes of purchased coal sold.

Gas cost of goods sold and other charges increased due primarily to increased unit costs.


	2005		2004		Variance			Percentage Change
Gas Sales Volumes (in billion gross cubic feet)		54.4		54.6		(0.2	)	(0.4	)%
Average Cost Per Thousand Cubic Feet	$	2.13	$	1.93	$	0.20		10.4	%

The increase in average cost per thousand cubic feet of gas sold was primarily attributable to increased royalty expense, offset, in part by changes in imbalance amounts. Royalty expense increased approximately $0.07 per thousand cubic feet in the 2005 period compared to the 2004 period primarily due to the 19.0% increase in average sales price per thousand cubic feet in the same periods. Additionally, the average cost per thousand cubic feet of gas sold increased due to a $0.03 increase per thousand cubic feet of gas sold related to the purchase of firm transportation capacity on the Columbia interstate pipeline because of potential curtailments on portions of shipment capacity allocated to CONSOL Energy as a result of increased demand for pipeline access in the 2005 period. Cost per unit increased $0.01 per thousand cubic feet of gas sold due to higher well maintenance fees. These fees have increased due to more wells being serviced in 2005. The increase in average unit costs was also due to an increase of approximately $0.02 per thousand cubic feet in the period-to-period comparison due to changes in the gas imbalance amounts. Because contracted quantities of gas delivered to the pipeline rarely equal physical deliveries to customers, CONSOL Energy is responsible for monitoring this imbalance and requesting adjustments to contracted volumes as circumstances warrant. The increase in imbalance cost per unit sold was offset by corresponding increases in gas sales revenue. In addition, unit costs increased $0.02 per thousand cubic feet due to additional power expense as a result of converting several compressors from gas powered to electric powered in the 2005 period. An increase of $0.05 per thousand cubic feet was attributable to various costs which were incurred throughout both periods, none of which were individually material.

In connection with the purchase of firm transportation capacity on the Columbia pipeline, we purchased from and sold to other gas suppliers, which increased our revenues and our costs. CONSOL Energy believes this type of transaction may continue as a result of increased capacity demands on the Columbia pipeline. The 2004 period included a smaller volume of firm transportation activity as we did not begin to purchase this capacity until May of 2004. Purchased gas information is as follows:


	2005		2004		Variance		Percentage Change
Purchased Gas Sales Volumes (in billion gross cubic feet)		28.7		17.5		11.2	64.0	%
Average Cost Per Thousand Cubic Feet	$	9.71	$	6.45	$	3.26	50.5	%

Industrial supplies cost of goods sold have increased $11 million primarily due to higher sales volumes.

Closed and idle mine cost of goods sold was $3 million lower in the 2005 period compared to the 2004 period primarily due to lower workers’ compensation expense. Workers’ compensation expense related to closed and idled locations has decreased $9 million primarily due to the actuarial effects of several law changes in the state of West Virginia related to workers’ compensation. Lower expense was also due to Emery being active for all of the 2005 period compared to being idled for most of the 2004 period. Other reductions in closed and idle mine cost of goods sold were due to various transactions that occurred throughout both periods, none of which were individually material. These improvements were offset, in part, by higher expenses related to mine closing, perpetual care water treatment and reclamation liability adjustments that were a result of updated engineering surveys. Survey adjustments resulted in $10 million of additional expense in the 2005 period for closed and idled locations compared to the results of the survey adjustments in the 2004 period.

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


	2005		2004			Dollar Variance		Percentage Change
Incentive compensation	$	35	$	25		$	10	40.0	%
Buchanan Mine fire		34		—			34	100.0	%
Buchanan skip hoist accident		3		—			3	100.0	%
Sales contract buy outs		13		9			4	44.4	%
Bank fees		12		12			—	—	%
Litigation settlements and contingencies		10		4			6	150.0	%
Coal Property holding costs		10		5			5	100.0	%
Stock-based compensation expense		4		1			3	300.0	%
Accounts receivable securitization fees		2		2			—	—	%
Other post employee benefit curtailment gain		—		(3	)		3	100.0	%
Buckeye landfill superfund site liability transfer		—		(1	)		1	100.0	%
Miscellaneous transactions		43		30			13	43.3	%

Total Miscellaneous Cost of Goods Sold and Other Charges	$	166	$	84		$	82	97.6	%

Incentive compensation expense increased due to an increase in the projected amount expected to be paid out to employees for the 2005 period compared to the 2004. The incentive compensation program is designed to increase compensation to eligible employees when CONSOL Energy reaches predetermined earnings targets and the employees reach predetermined performance targets.

CONSOL Energy’s Buchanan Mine, located near Keen Mountain, Virginia, experienced a large rock fall behind our longwall mining section on February 14, 2005. While caving behind the longwall is a normal part of the mining process, the size of this cave-in created a large air pressure wave that disrupted ventilation and also caused an ignition of methane gas in the area. CONSOL Energy temporarily sealed the mine in order to extinguish the fire that developed after the ignition. Various materials, including nitrogen foam and water were pumped into the mine in order to accelerate the process of creating an inert environment within the mine to extinguish the fire. Coal production resumed on June 16, 2005. Costs of goods sold incurred, net of expected insurance recovery, for the year ended December 31, 2005 were $34 million.

The Buchanan Mine was idled on September 16, 2005 following a problem with the mine’s skip hoist mechanism. Repairs to the skip hoist shaft and structures were completed and the mine resumed production on December 13, 2005. Expenses of approximately $3 million related to the damaged area were incurred during this time frame. Also, approximately $7 million were capitalized related to the installation and replacement of equipment and facilities damaged in the accident. We plan to file property damage and business interruption claims related to this incident. As of December 31, 2005, no insurance receivables have been recognized for these anticipated claims.

In the 2005 and 2004 periods, agreements were made to buy out sales contracts with several customers in order to release tons committed under lower priced contracts for sale to other customers at higher pricing.

Bank fees remained consistent in the period to period comparison.

Litigation settlements and contingencies increased in the 2005 period compared to the 2004 period. The increase is attributable to a proposed settlement agreement with certain lessors in western Kentucky which would require the transfer of certain properties and permits, as well as a cash payment to the lessors, with the lessors assuming all reclamation liability for the mine property which is being transferred. Various other contingencies were incurred in both periods, none of which were individually material.

Coal property holding costs increased in the 2005 period primarily due to leasehold surrenders that occurred in 2005.

In April 2004, CONSOL Energy began to issue restricted stock units as part of its equity incentive plan. Compensation cost for the restricted stock units is based upon the closing share price at the date of grant and is recognized over the vesting period of the units. The increase in stock-based compensation expense in the 2005 period is due to compensation cost for the 2004 grants being recognized for the full 2005 period as well as additional compensation costs for restricted stock unit grants that occurred in the 2005 period.

Accounts receivable securitization fees remained consistent in the period to period comparison.

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

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

Miscellaneous cost of goods sold and other charges increased $13 million due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

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

2005

2004

Dollar

Variance

Percentage

Change

Freight expense

120

110

9.1

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


	2005		2004		Dollar Variance		Percentage Change
Professional consulting and other purchased services	$	20	$	14	$	6	42.9	%
Wages and salaries		27		25		2	8.0	%
Other		34		34		—	—	%

Total Selling, General and Administrative	$	81	$	73	$	8	11.0	%

Costs of professional consulting and other purchased services were higher in the 2005 period compared to the 2004 period primarily due to services provided related to various corporate initiatives.

Wages and salaries have increased in the 2005 period due to additional employees hired in 2005.

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


	2005		2004		Dollar Variance			Percentage Change
Coal	$	214	$	234	$	(20	)	(8.5	)%
Gas:
Production		23		22		1		4.5	%
Gathering		12		11		1		9.1	%

Total Gas		35		33		2		6.1	%
Other		13		13		—		—	%

Total Depreciation, Depletion and Amortization	$	262	$	280	$	(18	)	(6.4	)%

The decrease in coal depreciation, depletion and amortization was primarily attributable to the acceleration of approximately $32 million of depreciation for equipment and facilities at Rend Lake and other idle mines in the 2004 period. CONSOL Energy’s management reviewed the assets at these idled locations in conjunction with changes in mine plans for these locations. No plan of use for these items was determined. These pieces of equipment and facilities were considered abandoned and estimated useful lives were adjusted accordingly. Rend Lake and the other idled locations have existing coal reserves that may be accessed through new facilities or from other active locations. This decrease was offset, in part, by additional equipment being placed in service at active locations, such as McElroy Mine, Bailey Mine and Enlow Mine, after the 2004 period. Increases were also attributable to expansion projects, such as McElroy and Bailey refuse area and plant expansion, that were completed and in service in the 2005 period.

The increase in gas production depreciation, depletion and amortization was primarily due to higher unit-of-production rates in the 2005 period compared to the 2004 period. Rates are generally calculated using the net book value of assets at the end of the year divided by proven developed reserves. Gathering depreciation, depletion and amortization is recorded on the straight-line method and increased due to additional assets coming on line in 2005.

Interest expense decreased in the 2005 period compared to the 2004 period.


	2005		2004		Dollar Variance			Percentage Change
Short-term borrowings	$	—	$	4	$	(4	)	(100.0	)%
12 year and 15 year secured notes		24		25		(1	)	(4.0	)%
Other		3		2		1		50.0	%

Total Interest Expense	$	27	$	31	$	(4	)	(12.9	)%

Interest expense decreased primarily due to a reduction in the weighted average outstanding balance under short-term borrowings in the 2005 period compared to the 2004 period. The weighted average outstanding balance was approximately $7 million in the 2005 period compared to $74 million in the 2004 period.

The decrease in interest expense related to the 12-year and 15-year secured notes is attributable to the scheduled long-term debt payment of $45 million for the 12-year secured note in June 2004.

Other interest expense increased due to reduced amounts of interest capitalized in the 2005 period compared to the 2004 period. The reduced capitalized interest was attributable to the lower level of capital projects funded from operating cash flow, primarily due to the completion of the McElroy expansion project.

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


	2005		2004		Dollar Variance		Percentage Change
Production taxes:
Coal	$	145	$	122	$	23	18.9	%
Gas		10		9		1	11.1	%

Total Production Taxes		155		131		24	18.3	%
Other taxes:
Coal		62		58		4	6.9	%
Gas		4		4		—	—
Other		8		5