Edgar Filing: CONSOL Energy Inc

For the Year
Ended December 31,

Total Produced (million 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, 2009;

¨	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.)

CNX Center

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(Address of principal executive offices including zip code)

Registrant’s telephone number including area code: 724-485-4000

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
Preferred Share Purchase Rights		New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned 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 Section 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 whether the registrant has submitted electronically and posted on its corporate website, if any, every interactive data file required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405) 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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

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, 2009, 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 $6,131,030,034.

The number of shares outstanding of the registrant’s common stock as of January 29, 2010 is 181,159,911 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of Consol Energy’s Proxy Statement for the Annual Meeting of Shareholders to be held on May 4, 2010,

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

TABLE OF CONTENTS


		Page
PART I

Item 1.	Business	5

Item 1A.	Risk Factors	39

Item 1B.	Unresolved Staff Comments	54

Item 2.	Properties	55

Item 3.	Legal Proceedings	55

Item 4.	Submission of Matters to a Vote of Security Holders	55

PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	56

Item 6.	Selected Financial Data	57

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	62

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	97

Item 8.	Financial Statements and Supplementary Data	99

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	175

Item 9A.	Controls and Procedures	175

Item 9B.	Other Information	177

PART III

Item 10.	Directors and Executive Officers of the Registrant	178

Item 11.	Executive Compensation	179

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	179

Item 13.	Certain Relationships and Related Transactions and Director Independence	179

Item 14.	Principal Accounting Fees and Services	179

PART IV

Item 15.	Exhibits and Financial Statement Schedules	180

SIGNATURES		187

FORWARD-LOOKING STATEMENTS

We are including the following cautionary statement in this Annual 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 Annual 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. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•

the continued weakness in global economic conditions or in any industry in which our customers operate, or sustained uncertainty in financial markets cause conditions we cannot predict;

•

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

•

reliance on customers honoring existing contracts, 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;

•

the disruption of rail, barge and other systems that deliver our coal;

•

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

•

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

•

our inability to maintain satisfactory labor relations;

•

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

•

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

•

foreign currency fluctuations could adversely affect the competitiveness of our coal abroad;

•

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 impact financial results;

•

increases in the price of commodities used in our mining operations could impact our cost of production;

•

obtaining governmental permits and approvals for our operations;

•

the effects of proposals to regulate greenhouse gas emissions;

•

the effects of government regulation;

•

the effects of stringent federal and state employee health and safety regulations;

•

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

•

uncertainties in estimating our economically recoverable coal and gas reserves;

•

the outcomes of various legal proceedings, which are more fully described in our reports filed under the Securities Exchange Act of 1934;

•

changes in existing federal and state income tax regulations;

•

increased exposure to employee related long-term liabilities;

•

minimum funding requirements by the Pension Protection Act of 2006 (the Pension Act) coupled with the significant investment and plan asset losses suffered during the recent economic decline has exposed us to making additional required cash contributions to fund the pension benefit plans which we sponsor and the multi-employer pension benefit plans in which we participate;

•

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

•

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

•

acquisitions that we recently have made or may make in the future including the accuracy of our assessment of the acquired businesses and their risks, achieving any anticipated synergies, integrating the acquisitions and unanticipated changes that could affect assumptions we may have made;

•

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

•

risks in exploring for and producing gas;

•

new gas development projects and exploration for gas in areas where we have little or no proven gas reserves;

•

the disruption of pipeline systems which deliver our gas;

•

the availability of field services, equipment and personnel for drilling and producing gas;

•

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;

•

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

•

our ability to acquire water supplies needed for drilling, or our ability to dispose of water used or removed from strata at a reasonable cost and within applicable environmental rules;

•

the coalbeds and other strata from which we produce methane gas frequently contain impurities that may hamper production;

•

the enactment of severance tax on natural gas in states in which we operate may impact results of existing operations and impact the economic viability of exploiting new gas drilling and production opportunities;

•

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

•

our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;

•

other factors discussed in our 2009 Form 10-K under “Risk Factors,” as updated by any subsequent Form 10-Qs, which are on file at the Securities and Exchange Commission.

Item 1.

Business.

CONSOL Energy’s History

We are a multi-fuel energy producer and energy services provider primarily serving the electric power generation industry in the United States. The electric power industry generates over two-thirds of its output by burning coal or gas, the two fuels we produce. During the year ended December 31, 2009, we produced high-British thermal unit (Btu) bituminous coal from 16 mining complexes in the United States. Coal produced from our mines has a high-Btu content which creates more energy per unit when burned compared to coals with lower Btu content. As a result, coals with greater Btu content can be more efficient to use. We are the majority shareholder (83.3%) of CNX Gas Corporation (CNX Gas). CNX Gas primarily produces pipeline-quality coalbed methane gas from our coal properties in the Northern and the Central Appalachian basin, and oil and gas from properties in the Appalachian and Illinois Basins. We believe that the use of coal and gas will continue to be the principal way in which the United States generates its electricity.

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 59 million tons of coal in 2009 accounted for approximately 6% of the total tons produced in the United States and approximately 13% of the total tons produced east of the Mississippi River during 2009. 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 control 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.

Our subsidiary, CNX Gas, also ranks as one of the largest coalbed methane gas companies in the United States based on both its proved reserves and its 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 strata of coal) with a high gas content;

•

We produced 94.4 billion cubic feet of gas in the year ended December 31, 2009;

•

At December 31, 2009, we had 3,926 net producing wells; and

•

We controlled approximately 1.9 trillion cubic feet of net proved reserves at December 31, 2009, of which 86% were coalbed methane reserves.

Additionally, we provide energy services, including river and dock services, terminal services, industrial supply services, coal waste disposal services and land resource management 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.

Industry Segments

the Northern Appalachian aggregated segment includes the following mines: Blacksville #2, Robinson Run, McElroy, Loveridge, Bailey, Enlow Fork, Mine 84 and Shoemaker. For the year ended December 31, 2009, the Central Appalachian aggregated segment includes the following mines: Jones Fork Complex, the Miller Creek Complex, the Fola Complex and the Terry Eagle Complex. For the year ended December 31, 2009, the Metallurgical aggregated segment includes the following mines: Buchanan and Amonate Complex. 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. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities, including rentals of building and flight operations. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years ended December 31, 2009, 2008 and 2007 is included in Note 25 of Notes to Audited Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.

Coal Operations

Mining Complexes

During the year ended December 31, 2009, CONSOL Energy had 16 active mining complexes, including a 49% equity affiliate, all 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, 2009 and 2008


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) 12/31/2008
Mine/Reserve	Location	Reserve Class	Coal Seam	Average Seam Thickness (feet)	Typical	Range	Owned (%)		Leased (%)		Tons in Millions 12/31/2009	Recoverable Reserves (tons in Millions) 12/31/2008
ASSIGNED—OPERATING
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)
Enlow Fork	Enon, PA	Assigned	Pittsburgh	5.4	12,940	12,860 – 13,060	100	%	—	%	48.9	160.3
		Accessible	Pittsburgh	5.3	12,900	12,830 – 13,000	79	%	21	%	197.9	185.3
Bailey	Enon, PA	Assigned	Pittsburgh	5.7	12,950	12,860 – 13,060	53	%	47	%	74.5	33.4
		Accessible	Pittsburgh	5.8	12,900	12,830 – 13,000	82	%	18	%	382.8	144.2
Mine 84	Eighty Four, PA	Assigned	Pittsburgh	5.4	13,120	12,950 – 13,250	100	%	—	%	11.3	26.9
		Accessible	Pittsburgh	5.8	13,050	12,880 – 13,180	66	%	34	%	68.3	86.7
McElroy	Glen Easton, WV	Assigned	Pittsburgh	5.9	12,570	12,450 – 12,650	100	%	—	%	195.0	201.5
		Accessible	Pittsburgh	5.8	12,530	12,410 – 12,610	94	%	6	%	153.0	69.0
Shoemaker	Moundsville, WV	Assigned	Pittsburgh	5.6	12,200	11,700 – 12,300	100	%	—	%	48.4	60.2
		Accessible	Pittsburgh	5.6	12,250	11,990 – 12,390	100	%	—	%	27.8	35.8
Loveridge	Fairview, WV	Assigned	Pittsburgh	7.5	13,150	13,070 – 13,370	84	%	16	%	37.9	47.0
		Accessible	Pittsburgh	7.6	13,100	13,020 – 13,320	95	%	5	%	13.6	25.7
Robinson Run	Shinnston, WV	Assigned	Pittsburgh	7.3	12,940	12,600 – 13,300	88	%	12	%	58.2	67.2
		Accessible	Pittsburgh	6.8	12,940	12,600 – 13,300	55	%	45	%	156.7	154.1
Blacksville #2	Wana, WV	Assigned	Pittsburgh	6.7	13,060	12,850 – 13,250	87	%	13	%	29.1	32.2
		Accessible	Pittsburgh	6.9	13,100	12,890 – 13,290	99	%	1	%	16.5	16.5
Harrison Resources(3)	Cadiz, OH	Assigned	Multiple	4.5	11,570	11,350 – 11,850	100	%	—	%	9.2	9.6

Central Appalachia (Virginia, Southern West Virginia, Eastern Kentucky)
Buchanan	Mavisdale, VA	Assigned	Pocahontas 3	5.7	13,980	13,700 – 14,200	19	%	81	%	68.4	39.9
		Accessible	Pocahontas 3	6.0	13,930	13,650 – 14,150	10	%	90	%	37.0	64.4
AMVEST—Fola Complex	Bickmore, WV	Assigned	Multiple	6.1	12,380	12,250 – 12,550	96	%	4	%	101.7	104.0
AMVEST—Terry Eagle Complex	Bickmore, WV	Assigned	Multiple	3.2	13,300	13,200 – 13,350	—	%	100	%	22.7	22.8
Jones Fork Complex	Mousie, KY	Assigned	Multiple	3.2	12,530	12,450 – 12,650	74	%	26	%	35.1	35.8
		Accessible	Multiple	3.4	12,330	12,250 – 12,450	100	%	—	%	1.4	1.4
Amonate Complex	Amonate, VA	Assigned	Multiple	3.8	13,100	12,850 – 13,350	70	%	30	%	19.6	19.6
Miller Creek Complex	Delbarton, WV	Assigned	Multiple	8.1	12,000	11,600 – 12,650	17	%	83	%	10.0	13.2
Western U.S. (Utah)
Emery	Emery Co., UT	Assigned	Ferron I	7.5	12,260	12,000 – 13,000	79	%	21	%	16.9	16.9

Total Assigned Operating and Accessible							78	%	22	%	1,841.9	1,673.6

(1)

The heat value shown for assigned reserves is based on the quality of coal mined and processed during the year ended December 31, 2009. 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 adjustments 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)	Harrison Resources is an equity affiliate in which CONSOL Energy owns a 49% interest. Reserves reported equal CONSOL Energy’s 49% proportionate interest in Harrison Resources’ reserves.

Excluded from the table above are approximately 109.2 million tons of reserves at December 31, 2009 that are assigned to projects that have not produced coal in 2009 or 2008. 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 52% owned and 48% 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, 2009, 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 Securities and Exchange Commission (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. Our coal reserves are periodically reviewed by an independent third party consultant. The independent consultant has reviewed the procedures used by us to prepare our internal estimates, verified the accuracy of approximately 97% of our property reserve estimates and retabulated reserve groups according to standard classifications of reliability.

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 (62%), central Appalachia (14%), the mid-western United States (18%), the western United States (4%), and in western Canada (2%) at December 31, 2009.

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

CONSOL Energy—UNASSIGNED Recoverable Coal Reserves as of 12/31/09


	As Received Heat Value(1) (Btu/lb)	Recoverable Reserves 12/31/09(2)					Recoverable Reserves (tons in millions) 12/31/2008
Coal Producing Region	As Received Heat Value(1) (Btu/lb)	Owned (%)		Leased (%)		Tons (in millions)	Recoverable Reserves (tons in millions) 12/31/2008
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)	11,400 – 13,500	70	%	30	%	1,239.7	1,437.1
Central Appalachia (Virginia, Southern West Virginia, Eastern Kentucky)	11,900 – 14,200	43	%	57	%	301.4	264.5
Illinois Basin (Illinois, Western Kentucky, Indiana)	11,500 – 11,900	43	%	57	%	780.6	780.6
Western U.S. (Wyoming)	9,400	100	%	—	%	169.1	169.1
Western Canada (Alberta)	12,400 – 12,900	—	%	100	%	77.9	77.9

Total		62	%	38	%	2,568.7	2,729.2

(1)

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.

(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.

The following table summarizes our proven and probable reserves as of December 31, 2009 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 by rank. Rank (High volatile A, B and C) of 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 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, 2009


	£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	—		—		—		—		—		162.3		—		—		—		162.3		3.6	%
Steam:
High Vol A Bituminous	—		—		—		—		—		111.0		54.4		123.4		2,328.0		2,616.8		57.9	%
Low Vol Bituminous	—		—		—		—		—		33.6		—		—		—		33.6		0.7	%

Region Total	—		—		—		—		—		306.9		54.4		123.4		2,328.0		2,812.7		62.2	%
Central Appalachia:
Metallurgical:
High Vol A Bituminous	33.6		4.9		22.6		—		—		18.3		—		—		1.3		80.7		1.8	%
Med Vol Bituminous	0.5		2.8		82.3		—		—		—		—		—		—		85.6		1.9	%
Low Vol Bituminous	—		—		124.5		2.3		—		26.2		—		—		—		153.0		3.4	%
Steam:
High Vol A Bituminous	38.3		73.4		14.1		61.6		46.2		61.7		0.8		2.5		5.2		303.8		6.8	%

Region Total	72.4		81.1		243.5		63.9		46.2		106.2		0.8		2.5		6.5		623.1		13.9	%
Midwest—Illinois Basin:
Steam:
High Vol B Bituminous	—		—		—		—		79.4		—		—		460.6		—		540.0		12.0	%
High Vol C Bituminous	—		—		—		—		159.5		—		108.3		—		—		267.8		5.9	%

Region Total	—		—		—		—		238.9		—		108.3		460.6		—		807.8		17.9	%
Northern Powder River Basin:
Steam:
Sub bituminous B	—		—		169.1		—		—		—		—		—		—		169.1		3.7	%

Region Total	—		—		169.1		—		—		—		—		—		—		169.1		3.7	%
Utah—Emery Field:
High Vol B Bituminous	—		16.9		—		—		12.3		—		—		—		—		29.2		0.6	%

Region Total	—		16.9		—		—		12.3		—		—		—		—		29.2		0.6	%
Western Canada:
Metallurgical:
Med Vol Bituminous	30.2		47.7		—		—		—		—		—		—		—		77.9		1.7	%

Region Total	30.2		47.7		—		—		—		—		—		—		—		77.9		1.7	%

Total Company	102.6		145.7		412.6		63.9		297.4		413.1		163.5		586.5		2,334.5		4,519.8		100.0	%

Percent of Total	2.3	%	3.2	%	9.1	%	1.4	%	6.6	%	9.1	%	3.6	%	13.0	%	51.7	%	100.0	%

CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES BY PRODUCT

(MILLIONS OF TONS) AS OF DECEMBER 31, 2009

The following table classifies CONSOL Energy coals by rank, projected sulfur dioxide emissions and heating value (British thermal units per pound). The table also classifies bituminous coals as medium and low volatile which is based on 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	33.6		4.9		22.6		—		—		180.6		—		—		1.3		243.0		5.4	%
Med Vol Bituminous	30.7		50.5		82.3		—		—		—		—		—		—		163.5		3.6	%
Low Vol Bituminous	—		—		124.5		2.3		—		26.2		—		—		—		153.0		3.4	%

Total Metallurgical	64.3		55.4		229.4		2.3		—		206.8		—		—		1.3		559.5		12.4	%
Steam:
High Vol A Bituminous	38.3		73.4		14.1		61.6		46.2		172.7		55.2		125.9		2,333.2		2,920.6		64.6	%
High Vol B Bituminous	—		16.9		—		—		91.7		—		—		460.6		—		569.2		12.6	%
High Vol C Bituminous	—		—		—		—		159.5		—		108.3		—		—		267.8		5.9	%
Low Vol Bituminous	—		—		—		—		—		33.6		—		—		—		33.6		0.8	%
Sub bituminous B	—		—		169.1		—		—		—		—		—		—		169.1		3.7	%

Total Steam	38.3		90.3		183.2		61.6		297.4		206.3		163.5		586.5		2,333.2		3,960.3		87.6	%

Total	102.6		145.7		412.6		63.9		297.4		413.1		163.5		586.5		2,334.5		4,519.8		100.0	%

Percent of Total	2.3	%	3.2	%	9.1	%	1.4	%	6.6	%	9.1	%	3.6	%	13.0	%	51.7	%	100.0	%

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


Region	Low		Medium	High
Northern, Central Appalachia and Canada	<	12,500	12,500 – 13,000	>	13,000
Midwest Appalachia	<	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 term 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 not exceed 1.2 pounds of sulfur dioxide per million British thermal units (1.2lb S02/MM BTU). 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. Clean air regulations that further restrict sulfur dioxide emissions will likely reduce significantly the amount of coal that can be used without post-combustion emission control technologies. Currently, a compliance coal will meet the power plant emission standard of 1.2 lb S02/MM BTU of fuel consumed. At December 31, 2009, 0.7 billion tons, or 15%, of our coal reserves met the current standard as a compliance coal. 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 coal’s sulfur content. In many cases, our customers have responded to compliance coal requirements by retrofitting flue gas desulfurization systems (scrubbers) to existing power plants. Because these systems remove sulfur dioxide before it is emitted into the atmosphere, our customers are less concerned about the sulfur content of our coal.

As a result of a 1998 court decision forcing the establishment of mercury emissions standards for power plants, the Environmental Protection Agency (EPA) also promulgated a regulatory program for controlling mercury. CONSOL Energy coals have mercury contents typical for their rank and location (approximately 0.07-0.15 parts mercury per million British thermal unit on a dry coal basis). Since CONSOL Energy coals have high heating values, they have lower mercury contents on a weight per energy basis (typically measured in pounds per British thermal units) than lower rank coals at a given mercury concentration. Eastern bituminous coals also 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 are also amenable to other methods of controlling mercury emissions, such as by powdered activated carbon injection. The EPA’s proposed control of mercury was recently vacated by a federal court requiring the EPA to develop a new proposal on mercury controls. Prior to federal court action, some states have already adopted a control program for mercury.

Production

In the year ended December 31, 2009, 91% of CONSOL Energy’s production came from underground mines and 9% from surface mines. Where the geology is favorable and reserves are sufficient, CONSOL Energy employs longwall mining systems in our underground mines. For the year ended December 31, 2009, 87% 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 years ended December 31, 2009, 2008 and 2007, 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

Tons Produced
(in millions)

Year
Established
or Acquired

2009

2008

2007

Northern Appalachia

Enlow Fork

Enon, Pennsylvania

LW/CM

R R/B

11.1

11.2

1990

Bailey

Enon, Pennsylvania

LW/CM

R R/B

10.4

10.0

9.9

1984

McElroy

Glen Easton, West Virginia

LW/CM

9.9

9.6

9.7

1968

Loveridge

Fairview, West Virginia

LW/CM

R T

6.0

5.2

6.6

1956

Robinson Run

Shinnston, West Virginia

LW/CM

R CB

5.6

6.5

1966

Blacksville 2(1)

Wana, West Virginia

LW/CM

R R/B T

3.8

5.6

5.1

1970

Mine No. 84(1)

Eighty Four, Pennsylvania

LW/CM

R R/B T

0.5

1.8

3.6

1998

Shoemaker(2)

Moundsville, West Virginia

LW/CM

0.4

1.1

—

1966

Harrison Resource Corporation(3)(4)

Cadiz, Ohio

S/L

R T

0.4

0.2

0.1

2007

Central Appalachia

Miller Creek Complex(3)

Delbarton, West Virginia

U/S

CM/S/L

3.2

3.1

1.4

2004

AMVEST-Fola Complex(1)(3)(5)

Bickmore, West Virginia

U/S

A S/L CM

3.0

3.9

1.8

2007

Buchanan(1)(6)

Mavisdale, Virginia

LW/CM

2.8

3.5

2.8

1983

Jones Fork Complex(1)(3)

Mousie, Kentucky

U/S

R T

1.1

2.5

3.1

1992

Amonate Complex(1)

Amonate, Virginia

U/S

CM/S/L

R T

—

0.4

0.6

1925

AMVEST-Terry Eagle Complex(5)

Jodie, West Virginia

U/S

CM A S/L

R T

—

0.4

0.1

2007

Mill Creek(3)(7)

Deane, Kentucky

U/S

—

1.1

1994

Western U.S.

Emery

Emery County, Utah

1.2

1.1

1.0

1945

A= Auger

S = Surface

U = Underground

LW = Longwall

CM = Continuous Miner

S/L = Stripping Shovel and Front End Loaders

R = Rail

B = Barge

R/B = Rail to Barge

T = Truck

CB = Conveyor Belt

(1)	Mine was idled for part of the year ended December 31, 2009 due to market conditions.

(2)	Mine was idled throughout most of 2009 due to converting from track haulage, to more efficient belt haulage to remove coal from the mine.

(3)	Harrison Resource Corporation, Miller Creek, Amvest Fola, Jones Fork and Mill Creek Complex include facilities operated by independent mining contractors.

(4)	Production amounts represent CONSOL Energy’s 49% ownership interest.

(5)	Mine Acquired in AMVEST Corporation acquisition on July 31, 2007.

(6)	Buchanan Mine was idled for part of the year ended December 31, 2008 and part of the year ended December 31, 2007 after several roof falls in previously mined areas damaged some of the ventilation controls inside the mine.

(7)	Mine was sold in February 2008.

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


	Years Ended December 31,
	2009		2008		2007
Average Sales Price Per Ton Produced	$	58.28	$	48.77	$	40.60

Construction on a new slope, overland belt and underground belt haulage system at our Shoemaker Mine in West Virginia was completed. The mine began production using the entire system in mid-January 2010. Construction of a new slope and overland belt at the Bailey Mine in Pennsylvania continued during 2009. The project is expected to be complete by the end of March 2010. Both projects are expected to improve productivity, increase production, reduce costs and enhance safety. Modern conveyor systems typically provide high availability rates, thereby allowing mining equipment to produce at higher levels. Overland belts do not require the daily maintenance of the mine roof that underground haulage systems require allowing manpower to be reduced or redeployed to more productive work. Mine safety is expected to be enhanced by the overland belts because older underground belt areas will be sealed.

The Buchanan Mine preparation plant was upgraded. The upgrades included an increase in capacity, construction of a second raw coal silo and an upgrade of the conveyor belt system at the preparation plant. The project was completed in August and has performed as expected. Also, construction of a reverse osmosis water treatment system (RO) was started during 2009. The RO system will provide a constant water source to the Buchanan preparation plant and provide water needed in the underground coal production at the mine. Construction of the RO is expected to be completed in the third quarter of 2010.

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 for the years ended December 31, 2009, 2008 and 2007.


Year	Total Royalty Tonnage (in thousands)	Total Coal Acreage Leased	Total Royalty Income (in thousands)
2009	11,403	232,181	$	16,448
2008	11,757	218,273	$	18,775
2007	13,909	218,089	$	11,362

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.

The following table ranks the 20 largest underground mines in the United States by tons of coal produced in calendar year 2008.

MAJOR U.S. UNDERGROUND COAL MINES—2008

In millions of tons


Mine Name	Operating Company	Production
Enlow Fork	CONSOL Energy	11.1
Bailey	CONSOL Energy	10.0
McElroy	CONSOL Energy	9.6
Twenty Mile	Peabody Energy Subsidiary	8.6
SUFCO	Arch Coal, Inc.	7.4
Cumberland Resources	Cumberland Resources, LP. (Foundation)	7.3
Century	American Energy Corp. (Murray)	6.9
Emerald Resources	Emerald Resources, LP. (Foundation)	6.3
San Juan	BHP Billiton	6.3
West Elk	Arch Coal, Inc.	6.1
Powhatan No. 6	The Ohio Valley Coal Company (Murray)	5.7
Robinson Run	CONSOL Energy	5.6
Blacksville 2	CONSOL Energy	5.6
Loveridge	CONSOL Energy	5.2
Warrier	Warrier Coal, LLC (Alliance)	5.1
Elk Creek	Oxbow Mining, LLC	4.9
Dotiki	Webster County Coal LLC (Alliance)	4.7
Dugout Canyon	Arch Coal, Inc.	4.3
Mountaineer 11/Mtn. Laurel	Arch Coal, Inc.	4.0
Highland	Highland Mining Co. LLC (Patriot)	3.9

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. In addition, we sell coal through agents and to brokers and unaffiliated trading companies. In 2009, we sold 58.1 million tons of coal, including our portion of equity affiliates. Eighty-eight percent (88%) of these sales were sold in domestic markets. Our direct sales to domestic electricity generators represented 83% of our total tons sold in 2009. We had approximately 90 customers in 2009. During 2009, no coal customers individually accounted for more than 10% of total revenue. However, the top four coal customers accounted for more than 25% of our total revenues.

Coal Contracts

We sell coal to customers under arrangements that are the result of both bidding procedures and unsolicited offers leading to 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, 2009, approximately 90% 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 with pre-established prices; or

•

Periodically negotiated prices that reflect market conditions at the time or are restricted to an agreed upon percentage increase or decrease; or

•

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

Several 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. Most of our contracts have terms no longer than five years. However, some of our contracts range in term from seven years to twenty years.

The following table sets forth, as of January 20, 2010, the total tons of coal CONSOL Energy is committed to deliver from 2010 through 2014.


	Tons/Dollars of Coal to be Delivered (Tons in millions of nominal tons)
	2010			2011		2012		2013		2014
Committed tons without pricing		1.3			18.3		20.9		22.1		22.1
Committed tons with firm pricing		59.7	*		24.1		8.2		4.2		0.3
Average realized price	$	55.06		$	51.92	$	51.45	$	49.14	$	57.36
Committed tons priced with collars		—			6.0		5.8		7.3		9.5
Average ceiling		—		$	63.46	$	51.61	$	51.38	$	52.00
Average floor		—		$	53.93	$	41.75	$	38.13	$	37.18

*	2010 Tons committed and priced include 3.1 million tons of metalurgical coal at a price of $96.00 per ton.

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

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 price reductions, damages, suspension of deliveries 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.

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 for certain customers. Most customers negotiate their own freight contracts.

At December 31, 2009 we operated 24 towboats, 5 harbor boats and a fleet of more than 650 barges that serve customers along the Ohio, Allegheny, Kanawha and Monongahela Rivers. The barge operation allows us to control delivery schedules and has served as temporary floating storage for coal when land storage is unavailable.

Competition

The United States coal industry is highly competitive, with numerous producers selling into all markets that use coal. 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 2008 National Mining Association Survey to have produced approximately 53% (based on tonnage produced) of the total United States production in 2008. The U.S. Department of Energy reported 1,435 active coal mines in the United States in 2008, 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 fuel 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 (CNX Gas), an 83.3% owned subsidiary of CONSOL Energy. Information presented below is 100% of CNX Gas’ basis; it does not include 16.7% noncontrolling interest reduction. CNX Gas 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. CNX Gas believes that this contributes to lower exploration costs than those incurred by producers that operate in deeper, less defined formations. However, we have continued to increase our exploratory efforts in the shale and deeper formations.

CNX Gas has not filed reserve estimates with any federal agency.

Areas of Operation

In the Appalachian Basin we operate principally in Central Appalachia and Northern Appalachia. We also operate in the Illinois Basin. Our primary operating areas are:

•

Central Appalachia, Virginia Operations coalbed methane (CBM), in Southwest Virginia, our traditional and largest area of operation, where we have typically produced CBM from vertical wells which we drill ahead of mining and gob gas wells;

•

Northern Appalachia, Mountaineer CBM in northwestern West Virginia and southwestern Pennsylvania where we drill vertical-to-horizontal CBM wells;

•

Northern Appalachia, Nittany CBM in central Pennsylvania, where we drill vertical CBM wells;

•

Northern Appalachia, Mountaineer-Conventional, in northwest West Virginia and southwest Pennsylvania, where we continue development in the Marcellus Shale and shallow conventional zones;

•

Northern Appalachia, Buckeye-Conventional in southeastern and central Ohio where we have begun drilling vertical exploration wells in the Marcellus and shallow conventional zones;

•

Tennessee, Knox-Chattanooga Shale, in eastern Tennessee, where we intend to convert our horizontal exploration program in the Chattanooga Shale into a full scale development program; and

•

Illinois Basin, Cardinal, in western Kentucky, Indiana and Illinois, where we are conducting an exploration program in the New Albany Shale and shallow oil zones.

In addition to the above areas, we believe we have Appalachian shale potential in the Huron shale. Additional potential exists in the Trenton Black River formation which is thought to underlie nearly all of the Appalachian shales. We will continue to evaluate our acreage position in these areas with the continuation of our exploration program.

Central Appalachia

Virginia Operations CBM

We have the rights to extract CBM in this region from approximately 405,000 net CBM acres, which cover a portion of our coal reserves in Central Appalachia. We produce gas primarily from the Pocahontas #3 seam which is the main coal seam mined by our Buchanan Mine. This seam is generally found at depths of 2,000 feet and generally ranges from 3 to 6 feet thick. The gas content of this seam is typically between 400 and 600 cubic feet of gas per ton of coal in place. In addition, there are as many as 50 thinner seams present in the several hundred feet above the main Pocahontas #3 seam. Collectively, this series of coal seams represents a total thickness ranging from 15 to 40 feet. We have access to over 1,300 core holes that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

We coordinate some of our CBM extraction with the subsurface coal mining of our Buchanan Mine. The initial phase of CBM extraction involves drilling a traditional vertical wellbore into the coal seam in advance of future mining activities. In general, we drill these wells into the coal seam ahead of the planned coal mining recovery in an area. To stimulate the flow of CBM to the wellbore, we fracture the coal seam by pumping water or inert gases into the coal seam. Once established, these fractures are maintained by further forcing sand into the fractures to keep them from closing, allowing CBM to desorb from the coal and migrate along the series of fractures into the wellbore. We refer to this type of well as a “frac well.” In 2009, frac wells account for approximately 76% of our Virginia production.

Because some of our gas is produced in association with subsurface mining, we have a unique opportunity to evaluate the effectiveness of our fracture techniques. We can enter the coal mine and inspect the fracture pattern created in the seam as the mining process exposes more of the coal. As a result, we have had the opportunity to gain insight into the efficiency of our fracturing techniques that is not available in a conventional production scenario. We have used this knowledge to modify and improve the effectiveness of our fracturing techniques.

Eventually, subsurface mining activities will mine through the frac wells that are drilled in advance of the mine development plan. As the main coal seam is removed from an area (called a “panel”), a rubble zone (called “gob”) is formed in the cavity created by the extraction of the coal. When the coal is removed, the rock above collapses into the void. These upper seams become extensively fractured and release substantial volumes of gas. We drill vertical wells (called “gob wells”) into the gob to extract the additional gas that is released. Approximately 10% of our 2009 Virginia gas production came from gob gas from active coal operations.

We also drill long horizontal wellbores into the coal seam from within active mines. We strategically locate these horizontal wells within the pattern of existing frac wells to further accelerate the desorption of CBM from the coal seam. We have drilled 15 of these “in-mine” horizontal wells, some of which have been extended to lengths of 5,000 feet. These wells show that a more efficient recovery of gas in place is possible ahead of mining operations. In-mine horizontal wells accounted for approximately 1% of Virginia production in 2009.

Virginia Operations Shale and Tight Sands

We have 224,000 net acres of Huron shale potential in Kentucky and Virginia; a portion of this acreage has tight sands potential.

Tennessee

The Chattanooga Shale in Tennessee is a Devonian-age shale found at a depth of approximately 3,500 feet. Shale thickness is between 40-80 feet, but CNX Gas has found it to be rich in total organic content. CNX Gas has 269,000 net acres of Chattanooga Shale. This largely contiguous acreage is composed of only a small number of leases, a rarity in Appalachia. CNX Gas is the operator of all of its Chattanooga Shale wells. CNX Gas believes that we drilled the first successful horizontal Chattanooga Shale well and that we have currently drilled more horizontal wells than any other operator in this play.

Northern Appalachia

Mountaineer CBM

We have the right to extract CBM in this region from approximately 799,000 net CBM acres, which contain most of our recoverable coal reserves in Northern Appalachia. We produce gas primarily from the Pittsburgh #8 coal seam. This seam is generally found at depths of less than 1,000 feet and generally ranges from 4 to 7 feet thick. The gas content of this seam is typically between 100 and 250 cubic feet of gas per ton of coal in place. There are additional coal seams above and below the Pittsburgh #8 seam. Collectively, this series of coal seams represents a total thickness ranging from 10 to 30 feet. We have access to nearly 8,000 data points that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

Due to the significant geological differences between the Pittsburgh #8 seam in Mountaineer and the Pocahontas #3 seam in Virginia, we have found that alternative extraction techniques are more effective than vertical frac wells in this area. Instead of using frac wells, we utilize well designs that rely on the application of vertical-to-horizontal drilling techniques. This well design includes a vertical wellbore that is intersected by a second well that has up to four horizontal lateral sections in the coal. Together, this well system facilitates extraction of CBM and water from the coal seam. The horizontal wellbores, extending up to 5,000 feet from the point of intersection with the vertical wellbore, expose large amounts of coal surface area allowing for the migration of water and CBM from the coal seam. The wells are spaced on approximately 480 acre sections. The vertical well, equipped with a mechanical pump, provides a sump for water produced by the coal seam to collect and enables the collected water to be lifted to the surface for disposal. In addition to our vertical-to-horizontal drilling, we also develop gob wells in this region associated with our coal mines.

Nittany CBM

We have the right to extract CBM in this region of Pennsylvania from approximately 260,000 net CBM acres, which contain most of our recoverable coal reserves as well as significant leases from other coal owners.

Marcellus Shale

We have substantially increased our acreage position in the Marcellus Shale from 186,000 net acres at December 31, 2008 to 250,000 net acres at December 31, 2009. We also have 161,000 net acres of shallow conventional potential in Ohio, Pennsylvania, West Virginia, and New York. In 2009, CNX Gas drilled and completed fourteen wells in the Marcellus Shale in southwestern Pennsylvania. Three wells were completed as vertical completions and the remaining eleven wells were drilled and completed as horizontal wells. All wells were turned into production as of December 31, 2009.

Shallow Oil and Gas

In 2009, CNX Gas drilled and completed six shallow conventional wells and drilled one shallow conventional well to total depth in south central Pennsylvania. Two additional shallow conventional wells were drilled and completed in eastern Ohio. Eight of the nine total wells are in production at December 31, 2009 while the remaining well is awaiting completion of gathering facilities for collection.

Others

Cardinal Shale

We control approximately 338,000 net acres of rights to gas in the New Albany shale in Kentucky, Illinois, and Indiana. The New Albany shale is a formation containing gaseous hydrocarbons, and our acreage position has thickness of 50-300 feet at an average depth of 2,500-4000 feet. In 2009, we continued testing the New Albany Shale which will lead us to drilling two horizontal wells in early 2010. We also have identified shallow oil and gas in which we produce two additional wells.

Illinois Basin CBM

We also control 515,000 net CBM acres in Illinois and Indiana, including 71,000 net CBM acres which contain most of our recoverable coal reserves in Illinois.

Other Acreage

We have the right to extract CBM on 139,000 net acres in the San Juan Basin, 20,000 net acres in the Powder River Basin, 41,000 net acres in eastern Ohio, and 51,000 net acres in central West Virginia. We also have the right to extract oil and gas on 12,000 net acres in the San Juan Basin, 10,000 net acres in the Powder River Basin, and 40,000 net acres in various other areas.

Summary of Properties as of December 31, 2009


	Central Appalachia		Northern Appalachia		Other		Total
Estimated Net Proved Reserves (billion cubic feet equivalent)	1,551		332		28		1,911
Percent Developed	56	%	42	%	100	%	54	%
Net Producing Wells (including gob wells)	3,363		492		71		3,926

Net Proved Developed CBM Acres	148,988		92,533		—		241,521
Net Proved Undeveloped CBM Acres	34,433		12,209		—		46,642
Net Unproved CBM Acres(1)	548,904		1,046,088		674,162		2,269,154

Total Net CBM Acres	732,325		1,150,830		674,162		2,557,317

Net Proved Developed Oil & Gas Acres	8,129		5,005		98		13,232
Net Proved Undeveloped Oil & Gas Acres	5,936		1,720		—		7,656
Net Unproved Oil & Gas Acres(1)	483,202		248,094		399,040		1,130,336

Total Net Oil & Gas Acres	497,267		254,819		399,138		1,151,224

(1)	Includes areas leased to others or participation interests in third party wells, as well as small acreage in other areas.

Development Wells (Net)

During the years ended December 31, 2009, 2008 and 2007, we drilled 247, 534 and 370 net development wells, respectively. Gob wells and wells drilled by other operators that we participate in are excluded. There was one dry development well in 2009. There were no dry development wells in 2008 or 2007. As of December 31, 2009, six wells are still in process. The following table illustrates the wells drilled referenced above by geographic region:


	For the Year Ended December 31,
	2009	2008	2007
Central Appalachia	202	321	294
Northern Appalachia	45	213	76

Total	247	534	370

Exploratory Wells (Net)

During the year ended December 31, 2009, 2008 and 2007, we drilled in the aggregate 18, 56 and 9 net exploratory wells, respectively. As of December 31, 2009, ten wells are still in process. The following table illustrates the exploratory wells drilled referenced above by geographic region:


	As of December 31,
	2009			2008			2007
	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.
Central Appalachia	6	—	4	8	—	18	3	—	—
Northern Appalachia	5	1	2	6	—	20	—	—	—
Other	—	—	—	1	3	—	1	—	5

Total	11	1	6	15	3	38	4	—	5

Summary of Other Operating Data

Production

The following table sets forth net sales volumes produced for the periods indicated. There was no production from equity affiliates for the years ended December 31, 2009 and 2008. The year ended December 31, 2007 included our portion of equity interests.

Average Sales Prices and Lifting Costs

The following table sets forth the average sales price and the average lifting cost (the year ended December 31, 2007 includes our portion of equity interests) for all of our gas production for the periods indicated, including intersegment transactions. Lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization.


	For the Year Ended December 31,
	2009		2008		2007
Average Gas Sales Price Before Effects of Financial Settlements (per thousand cubic feet)	$	4.15	$	8.99	$	6.87
Average Effects of Financial Settlements (per thousand cubic feet)	$	2.53	$	—	$	0.33
Average Gas Sales Price Including Effects of Financial Settlements (per thousand cubic feet)	$	6.68	$	8.99	$	7.20
Average Lifting Cost excluding ad valorem and severance taxes (per thousand cubic feet)	$	0.48	$	0.58	$	0.39

Productive Wells and Acreage

Most of our development wells and proved 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. The following table sets forth, at December 31, 2009, the number of CNX Gas producing wells, developed acreage and undeveloped acreage:


	Gross	Net(1)
Producing Wells (including gob wells)	5,240	3,926
Proved Developed Acreage	260,327	254,753
Proved Undeveloped Acreage	56,090	54,298
Unproven Acreage	3,957,174	3,399,490

Total Acreage	4,273,591	3,708,541

(1)

Net acres do not include acreage attributable to the working interests of our principal joint venture partners and the portions of certain proved developed acreage attributable to property we have leased to third-party producers. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.

We enter into physical gas sales transactions with various counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, other than interstate pipeline outages related to maintenance issues or a weather related force majeure event, we have not failed to deliver quantities required under contract. We 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 and represented approximately 51.6 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2009 at an average price of $8.76 per thousand cubic feet. As of December 31, 2009, we expect these transactions will cover approximately 45.7 billion cubic feet of our estimated 2010 production at an average price of $7.88 per thousand cubic feet, 22.6 billion cubic feet of our estimated 2011 production at an average price of $6.84 and 15.1 billion cubic feet of our estimated 2012 production at an average price of $6.84.

We have purchased firm transportation capacity on various interstate pipelines to ensure gas production flows to market. As of December 31, 2009, we have secured firm transportation capacity to cover more than our 2010, 2011 and 2012 hedged production.

The hedging strategy and information regarding derivative instruments used are outlined in “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Qualitative and Quantitative Disclosures About Market Risk” and in Note 23 to the Consolidated Financial Statements.

Reserves

The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the Securities and Exchange Commission (SEC).


	Net Reserves (Million cubic feet equivalent) as of December 31,
	2009		2008		2007
	Consolidated Operations	Affiliates	Consolidated Operations	Affiliates	Consolidated Operations	Affiliates
Proved developed reserves	1,040,257	—	783,290	—	667,726	3,584
Proved undeveloped reserves	871,134	—	638,756	—	672,183	—

Total proved developed and undeveloped reserves	1,911,391	—	1,422,046	—	1,339,909	3,584

Discounted Future Net Cash Flows

The following table shows our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%:


	Discounted Future Net Cash Flows (Dollars in millions)
	As of December 31,
	2009		2008		2007
Future net cash flows	$	2,391	$	2,824	$	3,609
Total PV-10 measure of pre-tax discounted future net cash flows(1)	$	1,480	$	2,004	$	2,288
Total standardized measure of after tax discounted future net cash flows	$	894	$	1,218	$	1,390

(1)

We calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-Generally Accepted Accounting Principle (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation to the most directly comparable GAAP measure—after-tax discounted future net cash flows.

Reconciliation of PV-10 to Standardized Measure


	As of December 31,
	2009			2008			2007
	(Dollars in millions)
Future cash inflows	$	7,975		$	8,857		$	9,509
Future production costs		(3,123	)		(3,526	)		(3,005	)
Future development costs (including abandonments)		(996	)		(794	)		(636	)

Future net cash flows (pre-tax)		3,856			4,537			5,868
10% discount factor		(2,376	)		(2,533	)		(3,580	)

PV-10 (Non-GAAP measure)		1,480			2,004			2,288

Undiscounted income taxes		(1,465	)		(1,714	)		(2,259	)
10% discount factor		879			928			1,361

Discounted income taxes		(586	)		(786	)		(898	)

Standardized GAAP measure	$	894		$	1,218		$	1,390

Competition

We operate primarily in the eastern United States. We believe 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. We believe that competition within our market is based primarily on gas commodity trading fundamentals and pipeline transportation availability to the diverse market opportunities.

Power Generation

Through a joint venture with Allegheny Energy Supply Company, LLC, an affiliate of one of our largest coal customers, CNX Gas owns a 50% interest in an 88-megawatt, gas-fired electric generating facility. This facility is used for meeting peak load demands for electricity. The facility is located in southwest Virginia and

uses coalbed methane gas that we produce. Because it is a peaking power facility, it does not operate at all times of the year, but the facility does provide a potential sales outlet for CNX Gas of up to 22 million cubic feet per day.

Other

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

Land Resources

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

•

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

•

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

•

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

•

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

CONSOL Energy’s objective is to improve the return on these assets without detracting from 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 28 customer service centers nationwide. Fairmont Supply also provides integrated supply procurement and management services. Integrated supply procurement is a materials management strategy that utilizes a single, full-line distribution to minimize total cost in the maintenance, repair and operating supply chain.

Fairmont Supply provides mine supplies to CONSOL Energy’s mining and gas operations. Approximately 44% of Fairmont Supply’s sales in 2009 were made to CONSOL Energy and CNX Gas’ operations.

Fairmont Supply Company’s 100% owned subsidiary, Piping and Equipment, is a specialty distributor of pipe, valve and fittings. Piping and Equipment has ten locations in Florida, Alabama, Louisiana and Texas. Fairmont Supply Company’s other 100% owned subsidiary, North Penn Pipe & Supply, LLC has locations in Warren and Troy, Pennsylvania, and distributes oil and gas field products, primarily tubular goods to the Northern Appalachia basin.

Terminal Services

In 2009, approximately 6.4 million tons of coal were shipped through CONSOL Energy’s subsidiary, CNX Marine Terminal Inc.’s, exporting terminal in the Port of Baltimore. Approximately 45% 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, Inc.

River and Dock Services

CONSOL Energy’s river operations, located in Monessen, Pennsylvania, transports coal from our mines, coal from other mines and non-coal commodities from river loadout facilities primarily along the Monongahela and Ohio Rivers in northern West Virginia and southwestern Pennsylvania. Products are delivered to customers along the Monongahela, Ohio, Kanawha and Allegheny rivers. At December 31, 2009, we operated 24 towboats, 5 harbor boats and more than 650 barges. In 2009, our river vessels transported a total of 17.3 million tons of coal and other commodities, including 6.1 million tons of coal produced by CONSOL Energy mines.

CONSOL Energy provides dock services for our mines as well for third parties at our Alicia Dock, located on the Monongahela River in Fayette County, Pennsylvania. 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. The ash disposal facility can process 200 tons of material per hour, and is expected to dispose of approximately 125 thousand tons of fly ash in the current contract year. 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, 2009, CONSOL Energy had 8,012 employees, approximately 34.5% of whom were represented by the United Mine Workers of America (UMWA). A five-year labor agreement commenced January 1, 2007. This agreement expires December 31, 2011 and provides for a 20% across-the-board wage increase over its duration. Wages increased $0.50 per hour in 2009, and will increase $0.50 per hour for 2010 through 2011. Other terms of the agreement require additional contributions to be made into the employee benefit funds. Full health-care benefits for active and retired members and their dependents continued with no increase in co-payments. Newly employed inexperienced employees represented by the UMWA, hired after January 1, 2007 will not be eligible to receive retiree health care benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked.

Laws and Regulations

The coal mining and gas industries 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, permitting and other licensing requirements, reclamation and restoration of properties after mining or gas operations are completed, management of materials generated by mining and gas operations, surface subsidence from underground mining, water discharge effluent limits, water appropriation, 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 analyses pertaining to the effect or impact that any proposed exploration for or production of coal or gas may have upon the environment, 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 and employee health and safety. 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 also post performance bonds or letters of credit pursuant to state oil and gas laws and regulations to guarantee reclamation of gas well sites and plugging of gas wells. 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 have been material. CONSOL Energy made capital expenditures for environmental control facilities of approximately $50.4 million, $10.6 million and $17.6 million in the years ended December 31, 2009, 2008 and 2007, respectively. The capital expenditures for environmental control facilities increased in 2009 primarily due to starting construction of a water processing system at Buchanan Mine. CONSOL Energy expects to have capital expenditures of $39.0 million for 2010 for environmental control facilities.

Mine Health and Safety Laws

Legislative and regulatory changes have required us to purchase additional safety equipment, construct stronger seals to isolate mined out areas, and engage in additional training. We have also experienced more aggressive inspection protocols resulting in the issuance of more citations and with new regulations the amount of fines have increased.

The actions taken thus far by federal and state governments include requiring:

•

the caching of additional supplies of self-contained self rescuer (SCSR) devices underground;

•

the purchase and installation of electronic communication and personal tracking devices underground;

•

the placement of rescue chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;

•

the reconstruction of existing seals in worked-out areas of mines;

•

the purchase of new fire resistant conveyor belting underground; and

•

additional training and testing that creates the need to hire additional employees.

Black Lung Legislation

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

•

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

•

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

•

a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner’s last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

The Affordable Health Choices Act currently being debated in the U.S. legislature provides for significant changes to the current Federal Black Lung Program. The current proposed legislative language would:

•

provide for an automatic survivor benefit to be paid upon the death of a miner with an awarded black lung claim without proving that death was due to coal workers’ pneumoconiosis; and

•

establish a rebuttable presumption if a miner had 15 or more years of coal mine employment and they were totally disabled by a respiratory condition that;

1. the miner is totally disabled due to pneumoconiosis;

2. that the miners death was due to pneumoconiosis;

3. or that at the time of death the miner was totally disabled by pneumoconiosis; and

•

be retroactive to claims filed or pending since 2005.

The proposed legislation could have a material impact on the cost of our Federal Black Lung Program. The impact of the proposed changes is dependent upon what is finally approved by the legislature.

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

Retiree Health Benefits Legislation

The Coal Industry Retiree Health Benefit Act of 1992 (the Act) established the Combined Benefit Fund (the Combined Fund). The Combined Fund provides medical and death benefits for all beneficiaries including orphan retirees of the former United Mine Workers of America (UMWA) Benefit Trusts who were actually receiving benefits as of July 20, 1992. The Act also created a second benefit fund for UMWA retirees, the 1992 Benefit Plan. The 1992 Benefit Fund principally provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and who actually retired between July 20, 1992 and September 30, 1994. The Act provides for the assignment of beneficiaries to former signatory employers or related companies and the allocation of unassigned beneficiaries (referred to as orphans) to the companies. The task of calculating the annual per beneficiary premium that assigned operators are obligated to pay to the Combined Fund is the responsibility of the Commissioner of Social Security.

The UMWA 1993 Benefit Plan is a defined contribution plan that was created as the result of negotiations for the National Bituminous Coal Wage Agreement (NBCWA) of 1993. This plan provides health care benefits to orphan UMWA retirees who are not eligible to participate in the Combined Fund, the 1992 Benefit Fund, or whose last employer signed the 1993 or later NBCWA, and who subsequently goes out of business.

The Act requires some of our subsidiaries to make premium payments to the Combined Fund and to the 1992 Benefit Plan for the cost of our retirees and orphan retirees in the Combined Fund and the 1992 Benefit Plan. In addition, the NBCWA of 2007 requires our signatory subsidiaries to make specified payments to the

1993 Benefit Plan through 2011. The Tax Relief and Health Care Act of 2006 (the 2006 Act) provides additional federal funding for these orphan costs by authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land (AML) trust fund. The additional federal funding, depending upon its magnitude and the amount of orphan benefits payable, should cover the orphan premium payments due under the Combined Fund as well as, after a phase-in period, the orphan premium payments due under the 1992 Benefit Plan. The 1992 Benefit Plan has a phase-in period for the federal contributions. Federal contributions were 25% in 2008 and 50% in 2009. Federal contributions will be 75% in 2010 and 100% thereafter. In addition, federal contributions are also to be phased-in over these same periods with respect to the costs for those orphan retirees as of December 31, 2006 under the 1993 Benefit Plan. Under the 2006 Act, these general fund contributions to the Combined Fund, the 1992 Benefit Plan, the 1993 Benefit Plan and certain Abandoned Mine Land payments to the states and Indian tribes are collectively limited by an aggregate annual cap of $490 million. These federal contributions do not apply to our subsidiaries’ assigned retired miners, and therefore our subsidiaries will continue to make premium payments for our assigned retired miners who receive benefits from the Combined Fund, the 1992 Benefit Plan and for certain beneficiaries of the 1993 Benefit Plan. In addition, our subsidiaries remain responsible for making orphan premium payments to these plans to the extent that the federal contributions are not sufficient to cover the benefits.

Pension Protection Act

The Pension Protection Act of 2006 (the Pension Act) has simplified and transformed rules governing the funding of defined benefit plans, accelerated funding obligations of employers, made permanent certain provisions of the Economic Growth and Tax Relief Reconciliation Act of 2001 (EGTRRA), made permanent the diversification rights and investment education provisions for plan participants and encourages automatic enrollment in defined contribution 401(k) plans. In general, most provisions of the Pension Act of 2006 are in effect for plan years beginning on or after December 31, 2008. Plans generally are required to set a funding target of 100% of the present value of accrued benefits and sponsors are required to amortize unfunded liabilities over a 7-year period. The Pension Act includes a funding target phase-in provision consisting of a 94% funding target in 2009, 96% in 2010 and 100% thereafter. Plans with a funded ratio of less than 80%, or less than 70% using special assumptions, will be deemed to be “at risk” and will be subject to additional funding requirements. The 2009 plan year funding ratio was 113%. The funding ratio is subject to year over year volatility and Internal Revenue Service’s calculation guidelines.

Environmental Laws

CONSOL Energy is subject to various federal environmental laws, including:

•

the Surface Mining Control and Reclamation Act of 1977,

•

the Clean Air Act,

•

the Clean Water Act,

•

the Toxic Substances Control Act,

•

the 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 federal or state agencies, as well as 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 surface mines as well as most aspects of deep mines. SMCRA 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 SMCRA 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 and wildlife, and 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 corporate ownership and control, property ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required by the OSM Applicant Violator System. We also must list all public and privately-owned structures located within 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 an administrative completeness review and a separate technical review. Public notice of the proposed permit application is given in a local newspaper followed by a public 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 can take six months to three years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance. The public has the right to comment on and otherwise participate in the permitting process, including through administrative appeals of permits and possibly further appeals in the courts. The mine operator must submit a bond or otherwise secure the performance of reclamation obligations, including, as deemed appropriate by the regulatory authority, 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 fully released is five years after reclamation has been completed, however, partial releases may be obtained as certain stages of reclamation are completed. 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 domestic water supplies adversely affected by underground mining. All states also impose an obligation on surface mining operations to replace domestic, agricultural or industrial water supplies adversely affected by such operations. In addition, SMCRA imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine

Reclamation Fund (AML Fund), which is used to restore unreclaimed and abandoned mine lands mined before 1977. The per ton fee is $0.315 for surface mined coal and $0.135 per ton for underground mined coal. From October 1, 2012 through September 30, 2021, the fees will be $0.28 per ton for surface mined coal and $0.12 per ton for underground mined coal.

Under 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. Data describing such ownership links must be provided by CONSOL Energy to the regulatory authorities. 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.

In the Commonwealth of Pennsylvania, where CONSOL Energy operates four longwall mines, approximately $10.3 million and $8.3 million of expenses were incurred during the years ended December 31, 2009 and 2008, respectively, to mitigate and repair impacts on streams from subsidence. Interpretations of technical guidance documents related to impacts of longwall mining on Pennsylvania streams require additional analysis on stream flows and biological statistics. We have received violation notices for past longwall activities which resulted in lower stream flows and water pooling areas both of which we are in the process of remediating. We also are completing additional stream analysis in order to comply with these recent interpretations at current Pennsylvania mining operations. Future Pennsylvania Department of Environmental Protection enforcement actions could cause CONSOL Energy to change mine plans, to incur significant costs, and potentially even shut down mines in order to meet compliance requirements. We currently estimate expenses related to subsidence of streams in Pennsylvania will be approximately $23.9 million for the year ended December 31, 2010.

Clean Air Act and Related Regulations

The federal Clean Air Act and similar state laws and regulations which regulate emissions into the air, affect coal mining, coal handling and processing, and gas processing operations primarily through permitting and/or emissions control requirements. For example, regulations relating to fugitive dust and coal combustion emissions could restrict CONSOL Energy’s ability to develop new mines or require CONSOL Energy to modify our operations. National Ambient Air Quality Standards (“NAAQS”) for particulate matter resulted in some areas of the country being classified as non-attainment for fine particulate matter. Because thermal dryers located at coal preparation plants burn coal and emit particulate matter, CONSOL Energy’s mining operations are likely to be directly affected where the NAAQS are implemented by the states.

CONSOL Energy believes we have obtained all necessary permits under the Clean Air Act. These permits have various expiration dates through March 2015. 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 the coal fired electric power generating plants operated by our customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. 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, nitrogen dioxide, and mercury emissions from electric power plants.

In October 1998, the EPA finalized a rule requiring a number of eastern U.S. states to make substantial reductions in nitrogen oxide emissions by June 1, 2004 (the NOX SIP call). Further sulfur dioxide and nitrogen oxide emission reductions were adopted by regulations called the Clean Air Interstate Rules (“CAIR”), which were promulgated by the EPA in 2005. In July and December 2008, the U.S. Court of Appeals for the District of Columbia remanded the CAIR regulations to EPA but did not vacate the regulations. The regulations were not vacated because many states were already implementing them and some coal fired electric generating facilities were being equipped with scrubbers in order to comply with the CAIR requirements. EPA’s position is that the CAIR rules are in effect and the states must implement them. EPA intends to adopt replacement regulations, but there is no specific schedule in place. 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 order to meet the proposed new limits for sulfur dioxide emissions from electric power plants, many 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. More strict emission limits mean few coals can be burned without the installation of supplemental environmental control technology in the form of scrubbers. Many of our customers are in the process of installing scrubbers in response to the CAIR emissions requirements. We estimate that by 2012, more than half of the installed, coal-fired power plant capacity east of the Mississippi will be scrubbed. The increase in scrubbed capacity allows customers to consider purchasing more of our higher sulfur coals.

In 2005, the EPA finalized the Clean Air Mercury Rule (“CAMR”) which imposed caps on mercury emissions from coal-fired electric generating units. The first phase of the emission caps would have taken effect in 2010. In February 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR. EPA has indicated that it will develop emission limits for mercury for coal fired electric generating facilities under Section 112 of the Clean Air Act, which requires EPA to impose maximum achievable control technology limits. In October 2008, New York and the New England states submitted a petition to EPA under the Clean Water Act requesting EPA to convene a conference to address contributions of airborne mercury emissions that upwind states are alleged to be making to downwind water quality. This petition appears to be aimed at coal fired power plants. Various states have promulgated or are considering more stringent emission limits on mercury emissions from coal-fired electric generating units. 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. One such suit was settled in October 2007, by the owner of sixteen coal fueled electric generating plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. Although the utility did not admit any violations of the Clean Air Act, it agreed to annual sulfur dioxide and nitrogen oxides emission limits for all of its plants and it agreed to install additional emission controls on two of its plants.

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, and several states have adopted measures intended to reduce greenhouse gas loading in the atmosphere. If comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States or individual states, it may adversely affect the use of and demand for fossil fuels, particularly coal, as an energy source for electricity generation. The U.S. Congress is considering climate change legislation that proposes to restrict greenhouse gas (GHG) emissions. President Obama

has pledged to implement an economy-wide cap-and-trade program to reduce GHG emissions 80 percent by 2050 and pledged that he would cause the United States to be a world leader on GHG reduction and re-engage with the United Nations Framework Convention on Climate Change to develop a global GHG program. In 2007, the U.S. Supreme Court held in Massachusetts v. Environmental Protection Agency (EPA), that the EPA had authority to regulate GHGs under the Clean Air Act and a number of states have filed lawsuits seeking to force the EPA to adopt GHG regulations. In December 2009, the EPA made a determination that GHGs cause or contribute to air pollution and may reasonably be anticipated to endanger public health or welfare, which findings are prerequisites to EPA regulating GHGs under the Clean Air Act. Moreover, several states have already adopted, and other states are considering the adoption of, legislation or regulations to reduce emissions of greenhouse gases. Such regulation would significantly increase the cost of generation of electricity at coal fired facilities and could make competing forms of electricity generation more competitive.

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. The Clean Water Act and corresponding state laws include requirements for: protection of “impaired waters” so designated by individual states through the use of new effluent limitations known as Total Maximum Daily Load (“TMDL”) limits; anti-degradation regulations which protect state designated “high quality/exceptional use” streams by restricting or prohibiting discharges which result in degradation; requirements to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids; and “protecting” streams, wetlands, other regulated water sources and associated riparian lands from surface mining and/or the surface impacts of underground mining. These requirements may cause CONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.

Permits for discharges of fill material into streams in connection with mining operations are issued by the Army Corps of Engineers (the “COE”). The COE is empowered to issue “nationwide” permits for specific categories of filing 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 of the Clean Water Act. 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. Since 2003, environmental groups have pursued litigation primarily in West Virginia and Kentucky challenging the validity of Nationwide Permit 21 and various individual permits authorizing valley fills associated with surface coal mining operations (primarily mountain top removal operations). This litigation has resulted in delays in obtaining these permits and has increased permitting costs. The most recent major decision in this line of litigation is the opinion of the United States Court of Appeals for the Fourth Circuit in Ohio Valley Environmental Council v. Aracoma Coal Company, 556 F.3d 177 (2009) (Aracoma), issued on February 13, 2009. Aracoma appeared to be a major victory for the coal industry because the Court rejected all of the substantive challenges to the Section 404 permits involved in the case primarily by deferring to the expertise of the COE in review of the permit applications. The effect of the Aracoma decision was quickly nullified by several EPA initiatives. First, in early 2009, the EPA began to comment on Section 404 permit applications pending before the COE raising many of the same issues decided in favor of the coal industry in Aracoma. Many of the EPA’s comment letters were submitted long after the end of the EPA’s comment period based on what the EPA contended was “new” information on the impacts of valley fills on stream water quality immediately downstream of valley fills. However, the comment letters addressed many issues beyond the “new” information on alleged water quality impacts, such as, minimization of the size and number of valley fills, cumulative impacts of the operation on the watershed, and the types and extent of mitigation. These comment letters practically resulted in a moratorium on the issuance of Section 404 permits for valley fills for coal surface mines. A second initiative of the EPA is “enhanced” review of any permit for a coal mining activity that requires both a SMCRA permit and a Section 404 permit in the states of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West

Virginia (designated as “Appalachian surface coal mining”). This initiative resulted in a joint Memorandum of Understanding (MOU) among the COE, the EPA and the Department of Interior (OSM). The “enhanced” review under the MOU has continued the delay in COE action on pending Section 404 permit applications. The EPA’s third initiative is to take a more active role in its review of NPDES permit applications for coal mining operations; especially in West Virginia where the EPA has decided to review all such NPDES permit applications. All of these initiatives have resulted in delays in the review and issuance of permits for surface coal mining applications. We anticipate that it will take longer to obtain permits and the costs of obtaining permits and compliance with permit conditions will increase significantly. So far, CONSOL Energy subsidiaries have been able to continue operating their existing mines. Also, in 2009 one subsidiary was able to obtain a Section 404 permit for a new surface mine in southern West Virginia. However, the new permit contains EPA mandated environmental protection conditions. Additionally, on January 4, 2010, the EPA published a notice in the Federal Register seeking public comment on the EPA’s enforcement and compliance priorities for fiscal years 2011 through 2013. The list of priorities includes energy/mining resource extraction (a new priority targeting mountain top removal mining).

A CONSOL Energy subsidiary is subject to a state administrative order in West Virginia that requires compliance in 2013 with effluent limits for chlorides for discharges from four active and two closed underground coal mines in northern West Virginia. Given the volumes of water involved and the options that are available to timely meet the effluent limits, it is likely that it will be necessary to construct one or more treatment facilities using advanced water treatment technologies. These requirements may cause CONSOL Energy to incur additional costs that could adversely affect our operating results, financial condition and cash flows.

Comprehensive Environmental Response, Compensation and Liability Act (Superfund)

The Comprehensive Environmental Response, Compensation and Liability Act (Superfund) and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. Our current and former coal mining operations incur, and will continue to incur, expenditures associated with the investigation and remediation of facilities and environmental conditions, including underground storage tanks, solid and hazardous waste disposal and other matters under Superfund 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 sites that have releases of hazardous substances. We have been in the past and currently are named as a potentially responsible party at Superfund sites. 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 (RCRA) 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.

RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion wastes generated at electric utility and independent power producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA resulting in coal combustion wastes remaining exempt from hazardous waste regulation. However, the EPA determined that national non-hazardous waste regulations under RCRA are needed for coal combustion wastes disposed in surface

impoundments and landfills and used as mine-fill, and the Office of Surface Mining is currently developing these regulations. The agency also concluded that beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. Most state hazardous waste laws also exempt coal combustion waste, and instead treat it as either a solid waste or a special waste. In response to the Tennessee Valley Authority coal ash spill in December 2008, the EPA initiated a fast-track regulatory process in which it is considering three possible regulatory scenarios for coal combustion wastes: regulation as a non-hazardous waste under Subtitle D of RCRA, regulation as a hazardous waste under Subtitle C, or a hybrid Subtitle C/D approach. Industry and state regulatory agencies are trying to convince the EPA that the states are adequately regulating handling and disposal of coal combustion wastes. The loss of the hazardous waste exemption for coal combustion waste, or the adoption of new regulations for disposing of coal combustion waste which impose significant additional costs, could adversely affect the demand for coal for electricity generation.

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. Currently, CONSOL Energy’s only active operation with federal coal leases is the Emery Mine.

Endangered Species Act

The Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection of endangered species may affect our ability to obtain permits, may delay issuance of mining permits, or may cause us to modify mining plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties.

Federal Regulation of the Sale and Transportation of Gas

Various aspects of our 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. 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. 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.

Regulations and orders set forth by the Federal Energy Regulatory Commission also impact our gas business to a certain degree. Although the Federal Energy Regulatory Commission does not directly regulate our gas production activities, the Federal Energy Regulatory Commission has stated that it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the Federal Energy Regulatory Commission continues to review its transportation regulations, including 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. Additional Federal Energy Regulatory Commission orders have been adopted based on this review with the goal of increasing competition for natural gas markets and transportation.

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. 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.

We own 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 may be pending before Congress, the Federal Energy Regulatory Commission, the Minerals Management Service, state commissions and the courts. We 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, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of CONSOL Energy or its subsidiaries. No material portion of our 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

Our 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, the disposal of fluids used in connection with operations, and gas operations producing coalbed methane in relation to active mining. Our 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, 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. A number of states have either enacted new laws or may be 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. Our gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although we do not believe that they would be affected by such regulation any differently than other natural gas producers or gatherers. However, these regulatory burdens may affect profitability, and we are unable to predict the future cost or impact of complying with such regulations.

Ownership of Mineral Rights

The majority of our drilling operations are conducted on properties related to our coal holdings.

CONSOL Energy’s past practice has been to acquire ownership or leasehold rights to our coal properties prior to conducting our coal mining operations. Given CONSOL Energy’s long history as a coal producer we believe we have a well-developed ownership position relating to our coal holdings. Although CONSOL Energy generally attempts to obtain ownership or leasehold rights to CBM and/or conventional gas related to our coal holdings, our ownership position relating to these property estates is less developed. As is customary in the coal and gas industry, a summary review of the title to coal, CBM and other gas rights is made on properties at the time of the acquisition of the other rights in the properties. Prior to the commencement of gas drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties; we are typically responsible for curing any title defects. We generally will not commence our drilling operations on a property until we have cured any material title defects on such property. We completed title work on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the gas industry.

The following summary sets forth an analysis of provisions of Pennsylvania, Virginia and West Virginia law relating to the ownership of CBM. These summaries do not purport to be complete and are qualified in their entirety by reference to the provisions of applicable law and rights and the laws relating to traditional natural gas resources may differ materially from the rights related to CBM. These summaries are based on current law as of the date of this Annual Report.

Pennsylvania

In Pennsylvania, CBM that remains inside the coal seam is generally the property of the owner of that coal seam where the gas is located. CBM can be sold in place or leased by the coal owner to another party such as a producer who then would have the right to extract the gas from the coal seam under the terms of the agreement with the coal owner. Once the gas migrates from the coal into other strata, the coal owner no longer has clear title to that migrated gas. As a result, in certain circumstances in Pennsylvania (e.g., in a gob or mine void), we may be required to obtain other property interests (beyond ownership or leasehold interest in the coal rights or CBM) in order to extract gas that is no longer located in the coal seam.

Virginia

The vast majority of CBM we produce, as well as our proved reserves, are in Virginia. The Virginia Supreme Court has stated that the grant of coal rights only does not include rights to CBM absent an express grant of CBM, natural gases, or minerals in general. The situation may be different if there is any expression in the severance deed indicating more than mere coal is conveyed. Virginia courts have also found that the owner of the CBM did not have the right to fracture the coal in order to retrieve the CBM and that the coal operator had the right to ventilate the CBM in the course of mining. In Virginia, we believe that we control the relevant property rights in order to capture gas from the vast majority of our producing properties.

In addition, Virginia has established the Virginia Gas and Oil Board and a procedure for the development of CBM by an operator in those instances where the owner of the CBM has not leased it to the operator or in situations where there are conflicting claims of ownership of the CBM. The general practice is to force pool both the coal owner and the gas owner. In those instances, any royalties otherwise payable are paid into escrow and the burden then is upon the conflicting claimants to establish ownership by court action. The Virginia Gas and Oil Board does not make ownership decisions.

West Virginia

The West Virginia Supreme Court has held that in a conventional oil and gas lease executed prior to the inception of widespread public knowledge regarding CBM operations, the oil and gas lessee did not acquire the right to produce CBM. As of December 31, 2009, the West Virginia courts have not clarified who owns CBM in West Virginia. Therefore, the ownership of CBM is an open question in West Virginia.

West Virginia has enacted a law, the Coalbed Methane Wells and Units Act (the “West Virginia Act”), regulating the commercial recovery and marketing of CBM. Although the West Virginia Act does not specify who owns, or has the right to exploit, CBM in West Virginia and instead refers ownership disputes to judicial resolution, it contains provisions similar to Virginia’s pooling law. Under the pooling provisions of the West Virginia Act, an applicant who proposes to drill can prosecute an administrative proceeding with the West Virginia Coalbed Methane Review Board to obtain authority to produce CBM from pooled acreage. Owners and claimants of CBM interests who have not consented to the drilling are afforded certain elective forms of participation in the drilling (e.g., royalty or owner), but their consent is not required to obtain a pooling order authorizing the production of CBM by the operator within the boundaries of the drilling unit. The West Virginia Act also provides that, where title to subsurface minerals has been severed in such a way that title to coal and title to natural gas are vested in different persons, the operator of a CBM well permitted, drilled and completed under color of title to the CBM from either the coal seam owner or the natural gas owner has an affirmative defense to an action for willful trespass relating to the drilling and commercial production of CBM from that well.

We anticipate in future years to more actively explore for and develop Northern Appalachian CBM in West Virginia. As indicated, we may need or desire to acquire additional rights from other holders of real estate interests, including acquiring rights from other real estate interest holders if the law at that time continues to lack clarity on ownership rights to CBM in West Virginia. As we explore and develop this other acreage where we have coal rights, we expect in accordance with our existing procedures to have a title examination performed of the rights to CBM. If we believe we need to obtain additional rights from the holders of other real estate interests, we have developed a methodology as part of deciding the feasibility of developing a particular tract to evaluate the ability to locate and negotiate a royalty arrangement with those other holders or use pooling provisions under the West Virginia Act.

Other States

We have rights to extract CBM where we have coal rights in other states. The ownership of CBM in the Illinois Basin and certain other western basins may be uncertain or could belong to other holders of real estate interests and we may need to acquire additional rights from other holders of real estate interests to extract and produce CBM in these other states.

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 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 “Directors and Executive Officers of CONSOL Energy” (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.

Continued weakness in global economic conditions or in any of the industries in which our customers operate, or sustained uncertainty in financial markets may have material adverse impacts on our business and financial condition that we currently cannot predict.

As widely reported, economic conditions in the United States and globally have deteriorated and the extent and timing of a recovery, especially in the United States and Europe, is uncertain. Financial markets in the United States, Europe and Asia have also experienced a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in security prices, severely diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States federal government and other governments. Unemployment has risen while business and consumer confidence have declined and there are fears of a prolonged recession in the United States and Europe. Although we cannot predict the impacts, continued weakness in the United States or global economies, in any of the industries we serve or in the financial markets could materially adversely affect our business and financial condition. For example:

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the demand for natural gas in the United States has declined and may remain at low levels or further decline if economic conditions remain weak and continue to negatively impact the revenues, margins and profitability of our natural gas business;

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the demand for electricity in the United States and for steel globally has declined and may remain at low levels or further decline if economic conditions remain weak and continue to negatively impact the revenues, margins and profitability of our steam and metallurgical coal businesses;

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the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables and the amount of receivables eligible for sale pursuant to our accounts receivable facility may decline;

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our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our coal or gas reserves; and

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our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.

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

Our financial results are significantly affected by the prices we receive for our coal and gas. Extended or substantial price declines for coal would adversely affect our operating results for future periods and our ability to generate cash flows necessary to improve productivity and expand operations. Prices of coal may fluctuate due to factors beyond our control such as overall domestic and global economic conditions; 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. Any adverse change in these factors could result in weaker demand and possibly lower prices for our production, which would reduce our revenues.

Gas prices are closely linked to consumption patterns of the electric generation industry and certain industrial and residential patterns where gas is the principal fuel. Natural gas prices are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. In the past we have used hedging transactions to reduce our exposure to market price volatility when we deemed it appropriate. If we

choose not to engage in, or reduce our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas and oil prices than our competitors who engage in hedging arrangements to a greater extent than we do. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as: the domestic and foreign supply of natural gas; the price of foreign imports; overall domestic and global economic conditions; the consumption pattern of industrial consumers, electricity generators and residential users; weather conditions; technological advances affecting energy consumption; domestic and foreign governmental regulations; proximity and capacity of gas pipelines and other transportation facilities; and the price and availability of alternative fuels. Many of these factors may be beyond our control. Lower natural gas prices may not only decrease our revenues on a per unit basis, but may also limit our access to capital. A significant decrease in price levels for an extended period would negatively affect us in several ways including our cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production; and access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable. Additionally, lower natural gas prices may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

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

During the year ended December 31, 2009, 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 is exercised, CONSOL Energy would be adversely affected if we are unable to replace the contracts or if new contracts are not at the same level of profitability. If existing customers do not honor current contract commitments, our revenue would be adversely affected. 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, including our production costs and other factors. Price changes, if any, provided in long-term supply contracts may not 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, 2009, we derived over 25% of our total revenues from sales to our four largest coal customers. At December 31, 2009, we had approximately 16 coal supply agreements with these customers that expire at various times from 2010 to 2028. 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 these customers may not continue to purchase coal from us under long-term coal supply agreements. If any one of these four 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 or if they fail to honor their contracts with us.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Some power plant owners may have credit ratings that are below investment grade. If the creditworthiness of our customers declines significantly, our $165 million accounts receivable securitization program and our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer’s contractual obligations are honored.

The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.

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 dams 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.

Competition within the coal and gas industries may adversely affect our ability to sell our products. 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.

Increases in coal prices could encourage existing producers to expand capacity or for new producers to enter the market. If overcapacity results, prices could fall or we may not be able to sell our coal, which would reduce revenue.

The gas industry is intensely competitive with companies from various regions of the United States and we may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, our operating results and financial position may be adversely affected. For example, one of our competitive strengths is being a low-cost producer of gas. If our competitors can produce gas at a lower cost than us, it would effectively eliminate our competitive strength in that area. In addition, larger companies may be able to pay more to acquire new gas properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our ability to acquire additional properties and to discover new gas resources also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.

We could be negatively affected if we fail to maintain satisfactory labor relations.

As of December 31, 2009, we had 8,012 employees. Approximately 35% of these employees are represented by unions. Union operations generated 46% of our U.S. coal production during the year ended December 31, 2009. Relations with our employees and, where applicable, organized labor is important to our success. If we do not maintain satisfactory labor relations with our organized and non-union employees, we may incur strikes, other work stoppages or have reduced productivity. Our labor costs may increase relative to other coal companies which could adversely affect our ability to compete with other coal companies and our results of operations.

The characteristics of coal may make it difficult for coal users to comply with various environmental standards. These standards are continually under review by international, federal and state agencies, related to coal combustion. As a result, coal users may switch to other alternative fuel or alternative energy sources, which would affect the volume of CONSOL Energy’s coal 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 alternative fuels. The Environmental Protection Agency continues to require reduction of nitrogen oxide emissions in a number of 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 may consider legislation to further control air emissions of multiple pollutants from electric generating facilities and other large emitters. Any new or 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. In addition, utilities may favor building new power plants fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fueled generators. Apart from alternative fuel sources, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by domestic

electric power generators as a result of new or proposed requirements or a switch to alternative fuels or renewable energy sources could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.

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

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.

Foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.

We compete in international markets against coal produced in other countries. Coal is sold internationally in U.S. dollars. As a result, mining costs in competing producing countries may be reduced in U.S. dollar terms based on currency exchange rates, providing an advantage to foreign coal producers. Currency fluctuations among countries purchasing and selling coal could adversely affect the competitiveness of our coal in international markets.

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 and affect production and 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 repairs;

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fires and other accidents; and

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weather conditions.

A decrease in the availability or increase in the costs of key services, capital equipment or commodities such as steel, liquid fuels and rubber products could impact our cost of production and decrease our anticipated profitability.

Coal mines consume large quantities of key services, capital equipment and commodities (including steel, copper, rubber products and liquid fuels). Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for these services and products are strongly impacted by the global market. A rapid or significant increase in their cost could impact our mining costs because we have a limited ability to negotiate lower prices, and, in some cases, do not have a ready substitute.

For mining and drilling operations, CONSOL Energy must obtain, maintain, and renew governmental permits and approvals which can be a costly and time consuming process and can result in restrictions on our operations.

Most producers in the eastern U.S. are being impacted by government regulations and enforcement to a much greater extent than a few years ago, particularly in light of the renewed focus by environmental agencies

and the government generally on the mining industry, including more stringent enforcement of the laws that regulate mining. The pace with which government issues permits needed for new operations and for on-going operations to continue mining has negatively impacted expected production, especially in Central Appalachia. Environmental groups in Southern West Virginia and Kentucky have challenged state and U.S. Army Corps of Engineers permits for mountaintop mining on various grounds. The most recent challenges have focused on the adequacy of the Corps of Engineers analysis of impacts to streams and the adequacy of mitigation plans to compensate for stream impacts resulting from valley fill permits required for mountaintop mining. In 2007, the U.S. District Court for the Southern District of West Virginia found other operators’ permits for mining in these areas to be deficient. In February 2009, the U.S. Court of Appeals for the Fourth Circuit reversed that decision, finding that the permits were adequate. However, since that reversal, the U.S. Environmental Protection Agency (EPA) began to more critically review valley fill permits and has been recommending that a number of permits be denied because of alleged concerns by EPA of potential impacts to water quality in streams below valley fills, with cumulative impacts of mining on watersheds and with adequacy of mitigation EPA’s objections and an enhanced review process that is being implemented under a federal multi-agency memorandum of understanding have effectively held up the issuance of permits for all types of mining operations that require valley fill permits, including surface facilities for underground mines, without any indication as to when normal permitting will resume. CONSOL Energy’s surface and underground operations have been impacted to a limited extent to date, but future permits will likely be delayed by the EPA’s current position, which will likely adversely impact our surface operations. In addition, over the past few years, the length of time needed to bring a new mine into production has increased by several years because of the increased time required to obtain necessary permits. New safety laws and regulations have impacted productivity at underground mines, although the company has not yet been able to ascertain the exact amount of the impact.

Proposals to regulate greenhouse gas emissions could impact the market for our fossil fuels, increase our costs and reduce the value of our coal and gas assets.

Global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (GHGs), such as carbon dioxide and methane. Combustion of fossil fuels, such as the coal and gas we produce, results in the creation of carbon dioxide that is currently emitted into the atmosphere by coal and gas end users, such as coal-fired electric generation power plants. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Further regulation of GHGs could occur in the United States pursuant to legislation, treaty obligations, regulation under the Clean Air Act, or states enacting new laws and regulations. Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (including the United States but has not been ratified by the United States) expires in 2012 and negotiations are underway for a new protocol. In 2007, the U.S. Supreme Court upheld in Massachusetts v. the Environmental Protection Agency (EPA), that the EPA had authority to regulate GHG’s under the Clean Air Act and a number of states have filed lawsuits seeking to force the EPA to adopt GHG regulations. President Obama has pledged to implement an economy-wide cap-and-trade program to reduce GHG emissions 80 percent by 2050. He also pledged the United States to be a world leader on GHG reduction and re-engage with the United Nations Framework Convention on Climate Change to develop a global GHG program. Apart from governmental regulation, on February 4, 2008, three of Wall Street’s largest investment banks announced that they had adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of utility power plants which may make it more difficult for utilities to obtain financing for coal-fired plants. If comprehensive laws focusing on GHGs emission reductions were to be enacted by the United States, individual states, in other countries where we sell coal, or if utilities were to have difficulty obtaining financing in connection with coal-fired plants, it may adversely affect the use of and demand for fossil fuels, particularly coal, which could have a material adverse effect on our results of operations, cash flows and financial condition.

In July 2008, the EPA published an Advance Notice of Proposed Rulemaking (“ANPR”) seeking comments and discussion of the complex issues associated with the possible regulation of GHGs under the Clean Air Act.

The deadline for comments on the ANPR was November 28, 2008. The EPA sought comments and discussion on: (i) advantages and disadvantages of regulating GHGs under various provisions of the Clean Air Act; (ii) how a decision to regulate GHGs under one provision of the Clean Air Act would lead to regulation under other provisions; (iii) issues relevant to legislation to regulate greenhouse gases and the potential overlap of the Clean Air Act and such future legislation; and (iv) scientific information relevant to, and the issues raised by, an analysis as to whether greenhouse gas emissions from automobiles may reasonably be anticipated to endanger public health or welfare. In December 2009, the EPA made a determination that GHGs cause or contribute to air pollution and may reasonably be anticipated to endanger public health or welfare, which findings are prerequisites to the EPA regulating GHGs under the Clean Air Act.

Coalbed methane must be expelled from our underground coal mines for mining safety reasons. Coalbed methane enhances the GHG effect to a greater degree than carbon dioxide. Our gas operations capture coalbed methane from our underground coal mines, although some coalbed methane is vented into the atmosphere when the coal is mined. If regulation of GHG emissions does not exempt the release of coalbed methane, we may have to curtail coal production, pay higher taxes, or incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines. The amount of coalbed methane we capture is recorded, on a voluntarily basis, with the U.S Department of Energy. We have recorded the amounts we have captured since the early 1990’s and our subsidiary, CNX Gas, has registered as an offset provider of credits with the Chicago Climate Exchange. If regulation of GHGs does not give us credit for capturing methane that would otherwise be released into the atmosphere at our coal mines, any value associated with our historical or future credits would be reduced or eliminated.

Existing and future government laws, regulations and other legal requirements relating to protection of the environment, health and safety matters and others that govern our business increase our costs of doing business for 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 and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, the installation of various safety equipment in our mines, control of surface subsidence from underground mining and work practices related to employee health and safety. 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 as a result of violations under environmental and health and safety laws. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities or new interpretations of existing legal requirements by regulatory bodies relating to the protection of the environment and health and safety matters could further affect our costs of operations and competitive position.

For example, 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. The Clean Water Act and corresponding state laws (including those relating to protection of “impaired waters” so designated by individual states through the use of new effluent limitations known as Total Maximum Daily Load (“TMDL”) limits; anti-degradation regulations which protect state designated “high quality/exceptional use” streams by restricting or prohibiting “discharges” which result in degradation; and requirements to treat discharges from coal mining properties for non-traditional pollutants requiring expensive treatment technologies, such as total dissolved solids, chlorides and selenium; and “protecting” streams, wetlands, other regulated water sources and associated riparian lands from the surface impacts of underground mining) may cause CONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and

cash flows or may prevent us from being able to mine portions of our reserves. The Clean Water Act is being used by opponents of mountain top removal mining as a means to challenge permits. Also, beginning in early 2009, EPA has relied upon the Clean Water Act to become more actively involved in the permitting of mountain top removal mining operations and other coal mining operations requiring permits to place fill in streams. 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 (Superfund) and similar state statutes and has been named as a potentially responsible party at Superfund sites in the past.

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

Our mines are subject to stringent federal and state safety regulations that increase our cost of doing business at active operations and may place restrictions on our methods of operation. In addition, government inspectors under certain circumstances, have the ability to order our operations to be shut down based on safety considerations.

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, the equipment used in mine emergency procedures, mine plans and other matters. The additional requirements of the Mine Improvement and New Emergency Response Act of 2006 (the Miner Act) and implementing federal regulations include, among other things, expanded emergency response plans, providing additional quantities of breathable air for emergencies, installation of refuge chambers in underground coal mines, installation of two-way communications and tracking systems for underground coal mines, new standards for sealing mined out areas of underground coal mines, more available mine rescue teams and enhanced training for emergencies. Most states in which CONSOL Energy operates have programs for mine safety and health regulation and enforcement. We believe that 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 place restrictions on our methods of operations, creating a significant effect on operating costs and productivity. In addition, government inspectors under certain circumstances, have the ability to order our operation to be shut down based on safety considerations.

CONSOL Energy has reclamation, mine closure and gas well plugging obligations. If the assumptions underlying our accruals are 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 and gas well drilling. CONSOL Energy accrues for the costs of current mine disturbance, gas well plugging and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing liabilities and gas well plugging, which are based upon permit requirements and our experience, were approximately $533 million at December 31, 2009. The amounts recorded are dependent upon a number of variables, including the estimated future closure 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.

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.

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.

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 our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 22,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi, New Jersey and Illinois. 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. For the year ended December 31, 2009, 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 and 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 and its subsidiaries are subject to various legal proceedings, which may have a material effect on our business.

We are party to a number of legal proceedings incident to normal business activities. There is the potential that an individual matter or the aggregation of many matters could have an adverse effect on our cash flows,

results of operations or financial position. See Note 24 in the Notes to the Audited Consolidated Financial Statements in Item 8 of the Form 10-K for further discussion.

Changes in federal or state income tax regulations, particularly in the area of percentage depletion, could cause our financial position and profitability to deteriorate.

The federal government has been reviewing the income tax regulations relating to the coal industry regarding percentage depletion benefits. If the percentage depletion tax benefit was reduced or eliminated, CONSOL Energy’s financial position could be materially impacted.

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, 2009, the current and non-current portions of these obligations included:

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postretirement medical and life insurance ($2.8 billion);

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coal workers’ black lung benefits ($194.6 million);

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salaried retirement benefits ($192.0 million); and

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workers’ compensation ($179.3 million).

However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Salary retirement benefits are funded in accordance with ERISA regulations. The other obligations are unfunded. In addition, the federal government and 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 a multi-employer pension plan, we have exposure under that plan that extends beyond what our obligation would be with respect to our employees.

Certain of our subsidiaries are obligated to contribute to a multi-employer defined benefit pension plan for United Mine Workers of America (UMWA) retirees. In the event of a partial or complete withdrawal by us from such pension plan, we would be liable for a proportionate share of such pension plan’s unfunded vested benefits, as determined by the plan's actuary. Based on the limited information available from the plan's administrators, which we cannot independently validate, we believe that our portion of the contingent liability represented by the pension plan's unfunded vested benefits, in the case of our withdrawal from the pension plan or the termination of the pension plan, could be material to our financial position and results of operations. In the event that any other contributing employer withdraws from such pension plan 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 a proportionate share of the pension plan’s unfunded vested benefits at the time of our withdrawal from the pension plan or its termination.

The minimum funding level requirements of the Pension Protection Act of 2006 (Pension Act) applicable to single employer and multi-employer defined benefit pension plans, coupled with significant investment asset losses suffered by such pension plans during the recent decline in equity markets and the current volatile economic environment, have exposed CONSOL Energy to having to make additional cash contributions to fund the pension benefit plans which we sponsor and the multi-employer pension benefit plans in which we participate.

CONSOL Energy sponsors a defined benefit retirement plan that covers substantially all of our employees not participating in multi-employer pension plans. For this pension plan, the Pension Act requires a funding target of 100% of the present value of accrued benefits. The Pension Act includes a funding target phase-in provision that establishes a funding target of 96% in 2010 and 100% thereafter for our defined benefit pension plan. Any such plan with a funded ratio of less than 80%, or less than 70% using special assumptions, will be

deemed to be “at risk” and will be subject to additional funding requirements under the Pension Act. The volatile economic environment and the deterioration in the equity markets have caused investment income and the value of investment assets held in our pension trust to decline and lose value. As a result, CONSOL Energy may be required to increase the amount of cash contributions it makes into the pension trust in order to meet the funding level requirements of the Pension Act.

Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan negotiated with the UMWA and contained in the National Bituminous Coal Wage Agreement (the “NBCWA”). The NBCWA currently calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The current contribution rates called for by the NBCWA are: $4.25 per hour worked in 2009, $5.00 per hour worked in 2010, and $5.50 per hour worked in 2011. These multi-employer pension plan contributions are expensed as incurred. The Pension Act requires a minimum funding ratio of 80% be maintained for this multi-employer pension plan. If the plan was determined to have a funded ratio of less than 80% it will be deemed to be “endangered” or "seriously endangered", and if less than 65%, it will be deemed to be in “critical” status, and will in either case be subject to additional funding requirements. Under the Pension Act, the multi-employer plan's actuary must certify the plan's funded status for each plan year. Based on an estimated funded percentage of 91.4%, a certification was provided by the multi-employer plan actuary, stating that the 1974 Pension Trust was in neither “endangered” nor “critical” status for the plan year beginning July 1, 2008. However, the volatile economic environment and the rapid deterioration in the equity markets caused investment income and the value of investment assets held in the 1974 Pension Trust to decline and lose value.

In late 2008, the Worker, Retiree and Employer Recovery Act of 2008 ("WRERA") was enacted. Under WRERA, a plan is permitted temporarily to avoid applying the Pension Act's requirements for improving its financial status by giving a plan the option to elect to retain its prior year zone status and to freeze the plan's zone status at the level determined for 2008. WRERA also required that the plan's actuary certify the plan's actual zone status for 2009. On September 28, 2009, based on an estimated funded percentage of 74%, the 1974 Pension Trust's actuary provided the Pension Act zone certification for 2009, certifying that the 1974 Pension Trust is “seriously endangered” for the plan year beginning July 1, 2009. Thereafter, pursuant to WRERA, the 1974 Pension Trust elected to retain its 2008 funded status of neither "endangered" nor “critical” for the plan year beginning July 1, 2009. If the freeze election had not been made, the 1974 Pension Trust's zone status for 2009 as certified by its actuary would have been "seriously endangered" and the 1974 Pension Trust would have been required to develop a funding improvement plan.

The freeze election only applies for the current plan year of 2009. If the 1974 Pension Trust is certified to be in endangered, seriously endangered or critical status for the plan year beginning July 1, 2010, steps will have to be taken under the Pension Act to improve its funded status. Such a determination would require certain subsidiaries of CONSOL Energy to make additional contributions pursuant to a funding improvement plan implemented in accordance with the Pension Act and, therefore, could have a material impact on our operating 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 for benefits earned up through December 31, 2005 in lieu of annual payments when they retire from CONSOL Energy. Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans for Terminations Benefits requires that if the lump-sum distributions made for a plan year 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. This type of adjustment may result in a material reduction in operating results.

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, coal workers’ black lung and other postemployment benefits.

Federal and state laws and regulations require us to provide 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. For certain requirements, there have been periods in the past when it has been 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.

Acquisitions that we have completed, acquisitions that we may undertake in the future, as well as expanding existing company mines involve a number of risks, any of which could cause us not to realize the anticipated benefits.

We have completed several acquisitions and mine and gas expansions in the past. We continually seek to grow our business by adding and developing coal and gas reserves through acquisitions; and by expanding the production at existing mines and existing gas operations. If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Mine expansion, gas operation expansion and acquisition transactions involve various inherent risks, including:

•

Uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of expansion and acquisition opportunities;

•

The potential loss of key customers, management and employees of an acquired business;

•

The ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition opportunity;

•

Problems that could arise from the integration of the acquired business; and

•

Unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or the acquisition opportunity.

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.

We face uncertainties in estimating proved 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 reserves 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 the timing of development expenditures may be incorrect. 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 historical average prices and costs. However, actual future net cash flows from our gas and oil properties also will be affected by factors such as:

•

geological conditions;

•

changes in governmental regulations and taxation;

•

assumptions governing future prices;

•

the amount and timing of actual production;

•

future operating costs; and

•

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. In addition, if natural gas prices decline by $0.10 per thousand cubic feet, then the pre-tax present value using a 10% discount rate of our proved reserves as of December 31, 2009 would decrease from $1.5 billion to $1.4 billion. The standardized Generally Accepted Accounting Principle measure associated with this decline of $0.10 per thousand cubic feet, would be approximately $0.8 billion.

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, 2009, 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. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Our exploration and development activities may not be commercially successful.

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

•

unexpected drilling conditions;

•

title problems;

•

pressure or irregularities in geologic formations;

•

equipment failures or repairs;

•

fires or other accidents;

•

adverse weather conditions;

•

reductions in natural gas prices;

•

pipeline ruptures; and

•

unavailability or high cost of drilling rigs, other field services and equipment.

Our future drilling activities may not be successful, and our drilling success rates could decline. Unsuccessful drilling activities could result in higher costs without any corresponding revenues.

Our focus on new development projects in our operating areas and other unexplored areas increases the risks inherent in our gas and oil activities.

We have little or no proved reserves in certain areas in Pennsylvania, Kentucky and Tennessee. These exploration, drilling and production activities will be subject to many risks, including the risk that CBM or other natural gas is not present in sufficient quantities in the coal seam or target strata, or that sufficient permeability does not exist for the gas to be produced economically. We have invested in property, and will continue to invest in property, including undeveloped leasehold acreage, that we believe will result in projects that will add value over time. Drilling for CBM, other natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs. We cannot be certain that the wells we drill in these new areas will be productive or that we will recover all or any portion of our investments.

Our business depends on transportation facilities owned by others. Disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our gas.

We transport our gas to market by utilizing pipelines owned by others. If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, our gas sales could be limited, reducing our profitability. If we cannot access pipeline transportation, we may have to reduce our production of gas or vent our produced gas to the atmosphere because we do not have facilities to store excess inventory. If our sales are reduced because of transportation constraints, our revenues will be reduced, and our unit costs will also increase. If we cannot obtain transportation capacity and we do not have the ability to store gas, we may have to reduce production. If pipeline quality tariffs change, we might be required to install additional processing equipment which could increase our costs. The pipeline could curtail our flows until the gas delivered to their pipeline is in compliance.

Increased industry activity may create shortages of field services, equipment and personnel, which may increase our costs and may limit our ability to drill and produce from our natural gas properties.

The demand for well service providers, related equipment, and qualified and experienced field personnel to drill wells and conduct field operations, including geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices,

causing periodic shortages. These shortages may lead to escalating prices, the possibility of poor services, inefficient drilling operations, and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to accidents sustained from the over use of equipment and inexperienced personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. In addition, the costs and delivery times of equipment and supplies are substantially greater in periods of peak demand. Accordingly, we cannot assure that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services in the future. Any such delays and price increases could adversely affect our ability to pursue our drilling program and our results of operations.

We may incur additional costs and delays to produce gas because we have to acquire additional property rights to perfect our title to the gas estate.

Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. Most of these properties were acquired 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 perform a thorough title examination of the gas estate before we commence drilling activities and to acquire any additional rights needed to perfect our ownership of the gas estate for development and production purposes. We may incur substantial costs to acquire these additional property rights and the acquisition of the necessary rights may not be feasible in some cases. Our inability to obtain these rights may adversely impact our ability to develop those properties. Some states permit us to produce the gas without perfected ownership under an administrative process known as “pooling,” which require us to give notice to all potential claimants and pay royalties into escrow until the undetermined rights are resolved. As a result, we may have to pay royalties to produce gas on acreage that we control and these costs may be material. Further, the pooling process is time-consuming and may delay our drilling program in the affected areas.

Our shale gas drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water when it flows back to the well-bore, and our CBM gas drilling and production operations require the removal and disposal of water from the coal seams, from which we produce gas. If we are unable to dispose of the water we use or remove from the strata at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.

New environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance.

Coal seams, frequently contain water that must be removed in order for the gas to detach from the coal and flow to the wellbore. Further, we must remove the water that we use to fracture our shale gas wells when it flows back to the well-bore. Our ability to remove and dispose of water will affect our production and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of waste, including, produced water, drilling fluids and other wastes associated with the exploration, development and production of natural gas.

Coalbed methane and other gas that we produce often contains impurities that must be removed, and the gas must be processed before it can be sold, which can adversely affect our operations and financial performance.

A substantial amount of our gas needs to be processed in order to make it saleable to our intended customers. At times, the cost of processing this gas relative to the quantity of gas produced from a particular

well, or group of wells, may outweigh the economic benefit of selling that gas. Our profitability may decrease due to the reduced production and sale of gas.

Enactment of a severance tax in several states where we have operations, including Pennsylvania, on natural gas could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in those states.

As a result of a funding gap in the Pennsylvania state budget due to significant declines in anticipated tax revenues, the Pennsylvania governor has proposed to its legislature the adoption of a wellhead or severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax is 5 percent of the value of the natural gas at wellhead plus 4.7 cents per thousand cubic feet of natural gas severed. In Pennsylvania we have rights in significant acreage for coalbed methane and other natural gas extraction on which we have drilled and expect to continue to drill producing wells. In 2009, 17% or 18.4 billion cubic feet, of our production was from Pennsylvania. In addition, a significant amount of our Marcellus shale play acreage is in Pennsylvania. We cannot predict whether Pennsylvania (or any other states) will adopt any such tax, nor if adopted the rate of tax. If states adopt such taxes, it could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities.

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

The vast majority of our producing properties are geographically concentrated in three counties in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of 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.

Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

To manage our exposure to fluctuations in the price of natural gas, we enter into hedging arrangements with respect to a portion of our expected production. As of December 31, 2009, we had hedges on approximately 45.7 billion cubic feet of our 2010 natural gas production, 22.6 billion cubic feet of our 2011 natural gas production and 15.1 billion cubic feet of our 2012 natural gas production. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges.

In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•

our production is less than expected;

•

the counterparties to our contracts fail to perform the contracts; or

•

the creditworthiness of our counterparties or their guarantors is substantially impaired.

If our gas hedges would no longer qualify for hedge accounting, we will be required to mark them to market and recognize the adjustments through current year earnings. This may result in more volatility in our income in future periods.

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.

The first through eighteenth paragraphs of Note 24 of the Notes to the Audited Consolidated Financial Statements included as Item 8 in Part II of this Form 10-K are incorporated herein by reference.

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, 2009:
Quarter Ended March 31, 2009	$	37.66	$	22.47	$	0.10
Quarter Ended June 30, 2009	$	44.13	$	24.01	$	0.10
Quarter Ended September 30, 2009	$	49.84	$	28.60	$	0.10
Quarter Ended December 31, 2009	$	53.50	$	42.18	$	0.10
Year Period Ended December 31, 2008:
Quarter Ended March 31, 2008	$	84.18	$	53.63	$	0.10
Quarter Ended June 30, 2008	$	119.10	$	67.33	$	0.10
Quarter Ended September 30, 2008	$	112.23	$	36.25	$	0.10
Quarter Ended December 31, 2008	$	44.95	$	18.50	$	0.10

As of December 31, 2009, there were 186 holders of record of our common stock. The computation of the approximate number of shareholders is based upon a broker search.

The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the common stock of CONSOL Energy to the cumulative shareholder return for the same period of a peer group and the Standard & Poor’s 500 Stock Index. The peer group is comprised of CONSOL Energy, Alliance Resource Partners, Alpha Natural Resources, Inc., Anadarko Petroleum Corp., Apache Corp., Arch Coal, Inc., Cabot Oil & Gas Corp., Callon Petroleum Co., Cheasapeake Energy, Corp., Climarex Energy, Co., Comstock Resources, Inc., Denbury Resources, Inc., Devon Energy Corp., Encana Corp., EOG Resources, Inc., International Coal Group, Inc., James River Coal Co., Massey Energy Co., Newfield Exploration Co., Nexen Inc., Noble Energy Inc., Peabody Energy Corp., Penn Virginia Corp., Pioneer Natural Resources Co., Rio Tinto PLC (ADR), St. Mary Land & Exploration, Stone Energy Corp., Ultra Petroleum Corp., and Westmorland Coal Co. The graph assumes that the value of the investment in CONSOL Energy common stock and each index was $100 at December 31, 2004. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2009.


	2004	2005	2006	2007	2008	2009
CONSOL Energy Inc.	100.0	160.1	159.5	283.1	223.6	299.2
Peer Group	100.0	158.1	161.4	221.7	170.8	218.8
S&P 500 Stock Index	100.0	104.8	120.4	125.8	89.2	115.1

Cumulative Total Shareholder Return Among CONSOL Energy Inc., Peer Group and

S&P 500 Stock Index

LOGO

The above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).

On January 29, 2010, CONSOL Energy’s board of directors declared a dividend of $0.10 per share, payable on February 19, 2010, to shareholders of record on February 9, 2010.

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, planned investments by CONSOL Energy and such other factors as the board of directors deems relevant. Our credit facility limits our ability to pay dividends when our leverage ratio covenant is 2.50 to 1.00 or greater or our availability is less than $100 million. The leverage ratio was 0.87 to 1.00 and our availability was approximately $317 million at December 31, 2009. The credit facility does not permit dividend payments in the event of defaults. There were no defaults in the year ended December 31, 2009.

See Part III, Item 12. “Security ownership of Certain Beneficial Owners and Management and Related Stockholders Matters” 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, 2009, 2008, 2007, 2006 and 2005 are derived from our audited Consolidated Financial Statements. Certain reclassifications of prior year data have been made to conform to the year ended December 31, 2009 as required by the Noncontrolling Interest Topic of the Financial Accounting Standards Board Accounting Standards Codification. 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 Operations” and the financial statements and related notes included in this report.

STATEMENT OF INCOME DATA

(In thousands except per share data)


	For the Years Ended December 31,
	2009			2008			2007			2006			2005
Sales—Outside	$	4,311,791		$	4,181,569		$	3,324,346		$	3,286,522		$	2,935,682
Sales—Purchased Gas		7,040			8,464			7,628			43,973			275,148
Sales—Gas Royalty Interests		40,951			79,302			46,586			51,054			45,351
Freight—Outside		148,907			216,968			186,909			162,761			119,811
Other Income		113,186			166,142			196,728			170,861			107,131
Gain on Sale of 18.5% interest in CNX Gas		—			—			—			—			327,326

Total Revenue and Other Income		4,621,875			4,652,445			3,762,197			3,715,171			3,810,449
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)		2,757,052			2,843,203			2,352,000			2,249,776			2,122,259
Purchased Gas Costs		6,442			8,175			7,162			44,843			278,720
Gas Royalty Interests Costs		32,376			73,962			39,921			41,879			36,501
Freight Expense		148,907			216,968			186,909			162,761			119,811
Selling, General and Administrative Expenses		130,704			124,543			108,664			91,150			80,700
Depreciation, Depletion and Amortization		437,417			389,621			324,715			296,237			261,851
Interest Expense		31,419			36,183			30,851			25,066			27,317
Taxes Other Than Income		289,941			289,990			258,926			252,539			228,606
Black Lung Excise Tax Refund		(728	)		(55,795	)		24,092			—			—

Total Costs		3,833,530			3,926,850			3,333,240			3,164,251			3,155,765

Earnings Before Income Taxes		788,345			725,595			428,957			550,920			654,684
Income Taxes		221,203			239,934			136,137			112,430			64,339

Net Income		567,142			485,661			292,820			438,490			590,345
Less: Net Income Attributable to Noncontrolling Interest		(27,425	)		(43,191	)		(25,038	)		(29,608	)		(9,484	)

Net Income Attributable to CONSOL Energy Inc. Shareholders	$	539,717		$	442,470		$	267,782		$	408,882		$	580,861

Earnings Per Share:
Basic	$	2.99		$	2.43		$	1.47		$	2.23		$	3.17

Dilutive	$	2.95		$	2.40		$	1.45		$	2.20		$	3.13

Weighted Average Number of Common Shares Outstanding:
Basic		180,693,243			182,386,011			182,050,627			183,354,732			183,489,908

Dilutive		182,821,136			184,679,592			184,149,751			185,638,106			185,534,980

Dividends Paid Per Share	$	0.40		$	0.40		$	0.31		$	0.28		$	0.28

BALANCE SHEET DATA

(In thousands)


	Year Ended December 31,
	2009			2008			2007			2006		2005
Working (deficiency) capital	$	(487,550	)	$	(527,926	)	$	(333,242	)	$	174,372	$	194,578
Total assets		7,725,401			7,370,458			6,208,090			5,663,332		5,071,963
Short-term debt		472,850			557,700			247,500			—		—
Long-term debt (including current portion)		468,302			490,752			507,208			552,263		442,996
Total deferred credits and other liabilities		3,849,428			3,716,021			3,325,231			3,228,653		2,726,563
CONSOL Energy Inc. Stockholders’ equity		1,785,548			1,462,187			1,214,419			1,066,151		1,025,356

OTHER OPERATING DATA

(unaudited)


	Year Ended December 31,
	2009		2008		2007		2006		2005
Coal:
Tons sold (in thousands) (D)(E)		58,123		66,236		65,462		68,920		70,401
Tons produced (in thousands)(E)		59,389		65,077		64,617		67,432		69,126
Productivity (tons per manday)(E)		38.21		36.80		41.29		38.41		37.95
Average production cost ($ per ton produced)(E)	$	44.87	$	41.08	$	33.68	$	32.53	$	30.06
Average sales price of tons produced ($ per ton produced)(E)	$	58.28	$	48.77	$	40.60	$	38.99	$	35.61
Recoverable coal reserves (tons in millions)(E)(F)		4,520		4,543		4,526		4,272		4,546
Number of active mining complexes (at end of period)		11		17		15		14		17
Gas:
Net sales volumes produced (in billion cubic feet)(E)		94.4		76.6		58.3		56.1		48.4
Average sales price ($ per mcf)(E)(G)	$	6.68	$	8.99	$	7.20	$	7.04	$	5.90
Average cost ($ per mcf)(E)	$	3.44	$	3.67	$	3.33	$	2.88	$	2.69
Proved reserves (in billion cubic feet)(E)(H)		1,911		1,422		1,343		1,265		1,130

CASH FLOW STATEMENT DATA

(In thousands)


	Year Ended December 31,
	2009			2008			2007			2006			2005
Net cash provided by operating activities	$	945,451		$	1,029,464		$	684,033		$	664,547		$	409,086
Net cash used in investing activities		(845,341	)		(1,098,856	)		(972,104	)		(661,546	)		(74,413	)
Net cash (used in) provided by financing activities		(173,015	)		166,253			105,839			(119,758	)		(455	)

OTHER FINANCIAL DATA

(Unaudited)

(In thousands)


	Year Ended December 31,
	2009		2008		2007		2006		2005
Capital expenditures	$	920,080	$	1,061,669	$	1,039,838	$	690,546	$	532,796
EBIT(I)		786,520		685,574		421,978		531,009		664,451
EBITDA(I)		1,223,937		1,075,195		746,693		827,246		926,302
Ratio of earnings to fixed charges(J)		11.76		10.67		7.48		11.36		15.95

(A)	See Note 25 of Notes to the Audited 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 share-based compensation granted, totaling 2,127,893 shares, 2,293,581 shares, 2,099,124 shares, 2,283,374 shares, and 2,045,072 shares for the year ended December 31, 2009, 2008, 2007, 2006 and 2005, respectively.

(C)

On May 4, 2006, CONSOL Energy’s Board of Directors declared a two-for-one stock split of the common stock. The stock split resulted in the issuance of approximately 92.5 million additional shares of common stock. Shares and earnings per share for all periods presented are reflected on a post-split basis.

(D)

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: 0.3 million tons in the year ended December 31, 2009, 1.7 million tons in the year ended December 31, 2008, 0.5 million tons in the year ended December 31, 2007, 1.3 million tons in the year ended December 31, 2006 and 1.5 million tons in year ended December 31, 2005.

(E)

Amounts include intersegment transactions. For entities that are not wholly owned but in which CONSOL Energy owns an equity interest, includes a percentage of their net production, sales and reserves equal to CONSOL Energy’s percentage equity ownership. For coal, the proportionate share of recoverable reserves for equity affiliates was 170, 171 and 179 tons at December 31, 2009, 2008 and 2007 respectively. Sales of coal produced by equity affiliates were 0.4 million tons in the year ended December 31, 2009, 0.2 million tons in the year ended December 31, 2008 and 0.1 million ton in the year ended December 31, 2007. Recoverable reserves and production amounts related to 2006 and 2005 for coal equity affiliates were immaterial. For gas, amounts include 100% of CNX Gas’ basis; they exclude the noncontrolling interest reduction. There was no equity in affiliates at December 31, 2009 and 2008. The proportionate share of proved gas reserves for equity affiliates was 3.6 Bcfe at December 31, 2007, 2.2 Bcfe at December 31, 2006 and 2.7 Bcfe at December 31, 2005. Sales of gas produced by equity affiliates were 0.32 Bcfe for the year ended December 31, 2007, 0.22 Bcfe for the year ended December 2006, 0.23 Bcfe for the year ended December 31, 2005.

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

(G)	Represents average net sales price including the effect of derivative transactions.

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

(I)

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:

(Unaudited)

(In thousands)


	Year Ended December 31,
	2009			2008			2007			2006			2005
Net Income	$	539,717		$	442,470		$	267,782		$	408,882		$	580,861
Add: Interest expense		31,419			36,183			30,851			25,066			27,317
Less: Interest income		(5,052	)		(2,363	)		(12,792	)		(15,369	)		(8,066	)
Less: Interest income included in black lung excise tax refund		(767	)		(30,650	)		—			—			—
Add: Income tax expense		221,203			239,934			136,137			112,430			64,339

Earnings before interest and taxes (EBIT)		786,520			685,574			421,978			531,009			664,451
Add: Depreciation, depletion and amortization		437,417			389,621			324,715			296,237			261,851

Earnings before interest, taxes and depreciation, depletion and amortization (EBITDA)	$	1,223,937		$	1,075,195		$	746,693		$	827,246		$	926,302

(J)

For purposes of computing the ratio of earnings to fixed charges, earnings represent income 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.

Item 7.

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

General

The U.S. economy began growing in the third quarter of 2009 and continued growing in the fourth quarter. Due to the significant fiscal spending and relaxed monetary policy in the United States, a modest recovery appears likely to continue in the U.S. through 2010. This should lead to an increase in demand for energy products from industrial customers, power generators and steel producers. Depending on the pace and sustainability of the recovery, we believe substantial opportunities exist for our metallurgical coal, thermal coal, and gas businesses.

Steel plant capacity utilization rates in the U.S. and globally continue to improve compared to last year. Domestic steel mills are using approximately 65% of their capacity, while Asian steel mills currently are using about 82% of their capacity. Chinese steel demand is again driving world demand and pricing for coking coal. Through its arrangement with Xcoal, CONSOL expects to increase its sales to Asian mills throughout 2010.

Going into the fourth quarter, thermal coal inventories were at historic highs. Because of the colder than normal weather in December 2009 and early January 2010, inventories at coal-fired power generators have been significantly drawn down, but are still somewhat higher than normal. Customers in our major market area (the PJM power pool) had an estimated 55-60 days of inventory on hand as of mid-January. The Company believes that thermal coal inventories could return to normal by mid-year. The outlook for a gradual economic recovery with strengthening demand and higher gas prices combined with the production declines over the past year are expected to tighten the thermal coal markets and support higher pricing. Higher gas prices in 2010 should result in power generators switching back from gas to coal based on dispatch economics. We anticipate up to 30 million tons of coal generation could displace natural gas generation in 2010. In addition, approximately 19 gigawatts of new coal-fired electricity generation capacity is set to come online by the end of 2012. This new demand, coupled with permanent cuts in coal production as well as safety and regulatory issues, is setting the stage for coal supply shortages over the next few years. With the continued build-out of scrubbers by generators, increased economic activity and its low cost position, CONSOL Energy is in a position to increase market share.

At the onset of the winter heating season, natural gas in storage fields was at record high levels. Because of much colder than normal weather in much of the U.S. from mid-December through mid-January, gas in storage has been drawn down to normal levels. The economic recovery is expected to positively affect industrial and commercial demand.

CONSOL Energy established an arrangement with Xcoal to market CONSOL Energy coal in Asia. In January 2010, we sold a vessel of high-vol coking coal from Bailey Mine in Northern Appalachia to merchant coke plants in China. This re-branding of Bailey Mine coal from a premium thermal coal to a high-volatile coking coal has meaningful implications for CONSOL Energy’s 2010 earnings and beyond. Our goal in 2010 is to sell 500,000 tons of Northern Appalachia high-volatile coking coal into Asian markets.

In 2009, a fish kill occurred in Dunkard Creek, which is a creek with segments in both Pennsylvania and West Virginia. The fish kill was caused by the growth of golden brown algae in the creek, which appears to be an invasive species, not indigenous to the area. A CONSOL Energy subsidiary discharges water into Dunkard Creek, after treatment, from its Blacksville No. 2 Mine and from its Loveridge Mine. This water has levels of chlorides that are higher than West Virginia in-stream limits. The subsidiary is subject to a state administrative order in West Virginia that requires compliance in 2013 with effluent limits for chlorides for discharges from four active and two closed underground coal mines in northern West Virginia. Given the volumes of water involved and the options that are available to timely meet the effluent limits, it is likely that it will be necessary to construct one or more treatment facilities using advanced water treatment technologies. These requirements may cause CONSOL Energy to incur additional costs that could adversely affect our operating results, financial condition and cash flows.

Results of Operations

Year Ended December 31, 2009 Compared with Year Ended December 31, 2008

Net Income Attributable to CONSOL Energy Shareholders

Net income attributable to CONSOL Energy shareholders changed primarily due to the following items

(table in millions):


	2009			2008			Dollar Variance			Percentage Change
Sales Outside	$	4,312		$	4,182		$	130		3.1	%
Sales Purchased Gas		7			8			(1	)	(12.5	)%
Sales Gas Royalty Interest		41			79			(38	)	(48.1	)%
Freight-Outside		148			217			(69	)	(31.8	)%
Other Income		113			166			(53	)	(31.9	)%

Total Revenue and Other Income		4,621			4,652			(31	)	(0.7	)%
Coal Cost of Goods Sold and Other Charges		2,757			2,843			(86	)	(3.0	)%
Purchased Gas Costs		6			8			(2	)	(25.0	)%
Gas Royalty Interest Costs		32			74			(42	)	(56.8	)%

Total Cost of Goods Sold		2,795			2,925			(130	)	(4.4	)%
Freight Expense		148			217			(69	)	(31.8	)%
Selling, General and Administrative Expense		132			125			7		5.6	%
Depreciation, Depletion and Amortization		437			390			47		12.1	%
Interest Expense		32			36			(4	)	(11.1	)%
Taxes Other Than Income		290			290			—		—
Black Lung Excise Tax Refund		(1	)		(56	)		55		(98.2	)%

Total Costs		3,833			3,927			(94	)	(2.4	)%

Earnings Before Income Taxes and Noncontrolling Interest		788			725			63		8.7	%
Income Tax Expense		221			240			(19	)	(7.9	)%

Earnings Before Noncontrolling Interest		567			485			82		16.9	%
Noncontrolling Interest		27			43			(16	)	(37.2	)%

Net Income Attributable to CONSOL Energy Inc. Shareholders	$	540		$	442		$	98		22.2	%

Net income attributable to CONSOL Energy shareholders for the year ended December 31, 2009 was $540 million compared to $442 million in the year ended December 31, 2008. Net income attributable to CONSOL Energy shareholders for the year ended December 31, 2009 increased in comparison to the year ended December 31, 2008 primarily due to:

•

Higher average thermal coal sales prices;

•

Higher gas sales volumes; and

•

Lower average cost per unit of gas sold.

Improvements in net income attributable to CONSOL Energy shareholders were offset, in part, by the following items:

•

Lower volume of thermal and metallurgical coal sold;

•

Lower average sales prices for gas volumes sold;

•

Lower average sales prices for metallurgical tons sold;

•

Higher average cost per ton of coal sold;

•

Business interruption insurance settlement of $50 million recognized in the year ended December 31, 2008 related to the Buchanan roof collapse incident; and

•

Black lung excise tax refunds of $56 million recognized in the year ended December 31, 2008.

See discussion below for additional details of the changes in net income in the year-to-year comparison. The cost per unit below is not necessarily indicative of unit costs in the future.

Revenue

Revenue and other income decreased due to the following items:


	2009		2008		Dollar Variance			Percentage Change
Sales:
Produced Coal—Thermal	$	3,148	$	2,669	$	479		17.9	%
Produced Coal—Metallurgical		223		398		(175	)	(44.0	)%
Purchased Coal		39		118		(79	)	(66.9	)%
Produced Gas		629		681		(52	)	(7.6	)%
Industrial Supplies		195		196		(1	)	(0.5	)%
Other		78		120		(42	)	(35.0	)%

Total Sales-Outside		4,312		4,182		130		3.1	%
Gas Royalty Interest		41		79		(38	)	(48.1	)%
Purchased Gas		7		8		(1	)	(12.5	)%
Freight Revenue		148		217		(69	)	(31.8	)%
Other Income		113		166		(53	)	(31.9	)%

Total Revenue and Other Income	$	4,621	$	4,652	$	(31	)	(0.7	)%

The increase in company produced thermal coal sales revenue during the year ended December 31, 2009 was due to the higher average price per ton sold, offset, in part, by lower sales volumes of company produced thermal coal sold.


	2009		2008		Variance			Percentage Change
Produced Thermal Tons Sold (in millions)		55.1		61.4		(6.3	)	(10.3	)%
Average Sales Price Per Thermal Ton	$	57.11	$	43.44	$	13.67		31.5	%

The increase in average sales price in the year-to-year comparison primarily reflects higher prices negotiated in previous periods when there was a significant increase in the global demand for coal. Sales of company produced coal shipments decreased in the current period due to delivery deferments of Central and Northern Appalachian coals. Coal consumption by the electric power sector continued to decline during the year. In the year-to-year comparison of the thermal coal changes, the increased pricing improved sales income by $753 million. This was partially offset by lower thermal tons sold which reduced sales income by approximately $274 million dollars.

The decrease in company produced metallurgical coal sales revenue during the year ended December 31, 2009 was due to the lower average price per ton sold and lower sales volumes of company produced metallurgical coal sold.


	2009		2008		Variance			Percentage Change
Produced Metallurgical Tons Sold (in millions)		2.3		2.9		(0.6	)	(20.7	)%
Average Sales Price Per Metallurgical Ton	$	96.68	$	136.92	$	(40.24	)	(29.4	)%

The decrease in average sales price for metallurgical coal in the year-to-year comparison reflects lower prices realized due to a downturn in the domestic and international steel business and the deferment of previously negotiated pricing into future periods. Sales of company produced metallurgical coal decreased in the current period due to a downturn in the domestic and international steel business resulting in reduced demand for metallurgical coal and the idling of the Buchanan Mine from March 1, 2009 to August 7, 2009. In the year-to-year comparison of metallurgical coal changes, the decreased pricing impaired sales income by $93 million. Also, lower metallurgical tons sold impaired sales income by approximately $82 million dollars.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased from third parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants. The decrease of $79 million in purchased coal sales revenue was primarily due to a decrease in demand in the year-to-year comparison, offset, in part, by higher sales prices.

The decrease of $52 million in produced gas sales revenue in the year ended December 31, 2009 compared to the year ended December 31, 2008 was due to lower average sales price per thousand cubic feet sold, offset, in part, by higher sales volumes.


	2009		2008		Variance			Percentage Change
Produced Gas Sales Volume (in billion cubic feet)		93.6		75.3		18.3		24.3	%
Average Sales Price Per thousand cubic feet	$	6.72	$	9.04	$	(2.32	)	(25.7	)%

Sales volumes increased as a result of additional wells coming online from our on-going drilling program. The decrease in average sales price is the result of the general market price decreases in the year-to-year comparison. The general market price decline was offset, in part, by the various gas swap transactions entered into by CNX Gas. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 51.6 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2009 at an average price of $8.76 per thousand cubic feet. In the year ended December 31, 2008, these financial hedges represented approximately 43.4 billion cubic feet at an average price of $9.25 per thousand cubic feet.

The $1 million decrease in revenues from the sale of industrial supplies was primarily due to lower sales volumes. Economic conditions had a negative impact on major customers, particularly those serving the auto and housing markets.

The $42 million decrease in other sales was attributable to decreased revenues from barge towing and terminal services. The decrease is related to lower tonnage moved by the barge towing and terminal services in the year ended December 31, 2009 compared to the year ended December 31, 2008. Lower tonnage moved reflects the weak economic environment which has reduced the volume of products moved on the rivers in the year ended December 31, 2009.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The decrease in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the year-to-year change.


	2009		2008		Variance			Percentage Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		9.8		8.5		1.3		15.3	%
Average Sales Price Per thousand cubic feet	$	4.17	$	9.32	$	(5.15	)	(55.3	)%

Purchased gas sales volumes represent volumes of gas, sold at market prices, that were purchased from third-party producers.


	2009		2008		Variance			Percentage Change
Purchased Gas Sales Volumes (in billion cubic feet)		1.6		1.0		0.6		60.0	%
Average Sales Price Per thousand cubic feet	$	4.46	$	8.76	$	(4.30	)	(49.1	)%

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. Freight revenue has decreased $69 million in 2009 primarily due to lower domestic shipments to customers for whom CONSOL Energy pays the freight and then passes on the cost to the customer. Freight revenue also decreased due to fewer export sales made to customers whom CONSOL Energy pays the ocean-going freight and then passes the cost to the customer.

Other income consists of interest income, gain or loss on the disposition of assets, equity in earnings of affiliates, service income, royalty income and miscellaneous income.


	2009		2008		Dollar Variance			Percentage Change
Business interruption proceeds	$	—	$	50	$	(50	)	(100.0	)%
Gain on sale of assets		15		23		(8	)	(34.8	)%
Contract towing		5		11		(6	)	(54.5	)%
Proceeds from relinquishment of mining rights		—		6		(6	)	(100.0	)%
Royalty income		17		21		(4	)	(19.0	)%
Recognition of unrealized gains on options		2		—		2		100.0	%
Interest income		5		2		3		150.0	%
Equity in earnings of affiliates		16		11		5		45.5	%
Contract settlement		12		—		12		100.0	%
Other miscellaneous		41		42		(1	)	(2.4	)%

Total other income	$	113	$	166	$	(53	)	(31.9	)%

In March 2008, CONSOL Energy received notice from its insurance carriers that $50 million would be paid as final settlement of the insurance claim related to the July 2007 Buchanan Mine incident that idled the mine. The $50 million represented business interruption coverage which was recognized in other income; the coal segment recognized $42 million and the gas segment recognized $8 million. The final settlement brought the total amount recovered from insurance carriers to $75 million, the maximum allowed per covered event.

Gain on sale of assets decreased $8 million in the year-to-year comparison due to 2008 including the sale of an idled facility which included the transfer of the mine closing liabilities to the buyer. This transaction resulted in $8 million pre-tax gain in 2008. Both periods also include various miscellaneous transactions, none of which were individually material.

Contract towing revenue has decreased approximately $6 million due primarily to the general slow-down in the economy negatively impacting the volume of material being shipped via river transportation.

The year ended December 31, 2008 includes $6 million of proceeds received from a third party in order for CONSOL Energy to relinquish the mining of certain in-place coal reserves.

Royalty income decreased $4 million primarily due to lower volumes of CONSOL Energy coal produced by third-parties.

In 2009, mark-to-market adjustments for free standing coal sales options resulted in approximately a $2 million reversal of previously recognized unrealized losses. The reversal of losses was due to the options expiring during the year ended December 31, 2009.

Interest income increased $3 million primarily due to higher average cash balances available to invest in the year-to-year comparison.

Equity in earnings of affiliates increased $5 million in the year ended December 31, 2009 due to various transactions entered into by our equity affiliates throughout both periods, none of which were individually material.

In 2009, $12 million of income was recognized related to contracts with certain customers that were unable to take delivery of previously contracted coal tonnage. These customers agreed to buy out their contracts in order to release them from the requirement of taking delivery of previously committed tons.

Other miscellaneous income decreased $1 million in the year-to-year comparison due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Costs

Cost of goods sold and other charges decreased due to the following:


	2009		2008	Dollar Variance			Percentage Change
Cost of Goods Sold and Other Charges
Produced Coal	$	1,968	2,031	$	(63	)	(3.1	)%
Purchased Coal		46	124		(78	)	(62.9	)%
Produced Gas		204	184		20		10.9	%
Industrial Supplies		185	186		(1	)	(0.5	)%
Closed and Idle Mines		114	78		36		46.2	%
Other		240	240		—		—

Total Cost of Goods Sold and Other
Charges Outside		2,757	2,843		(86	)	(3.0	)%
Gas Royalty Interest		32	74		(42	)	(56.8	)%
Purchased Gas		6	8		(2	)	(25.0	)%

Total Cost of Goods Sold	$	2,795	2,925	$	(130	)	(4.4	)%

Produced coal cost of goods sold and other charges decreased primarily due to lower sales volumes, offset, in part, by an 8.6% increase in average unit cost per ton sold.


	2009		2008		Variance			Percentage Change
Produced Tons Sold (in millions)		57.4		64.3		(6.9	)	(10.7	)%
Average Cost of Goods Sold and Other Charges per Ton	$	34.27	$	31.57	$	2.70		8.6	%

Average cost of goods sold and other charges per unit increased in the year-to-year comparison primarily due to an increase in average unit costs related to the following items:

•

In general, average cost of goods sold per unit has increased due to the reduced amount of tons sold from CONSOL Energy mines. The reduction in tons sold reflects the weak economic environment which has affected electricity generation and correspondingly the demand for coal. Fixed costs incurred at our mining operations are now spread over fewer tons sold, which has negatively impacted average unit costs.

•

Supply costs have increased $1.39 per ton sold related to higher supply and maintenance costs at several locations. Additional supply and maintenance projects were related to additional preparation

plant maintenance, additional belt advancement costs, additional mining equipment maintenance, additional roof support, additional use of contract labor to complete belt projects and additional water handling costs. These increased supply and maintenance costs were offset, in part, by fewer seals being constructed in previously mined areas. Average unit costs of supplies were also impacted by lower sales tons in the year-to-year comparison.

•

Labor costs have increased $0.91 per ton sold due to the effects of wage increases at the union and non-union mines. These contracts call for specified hourly wage increases in each year of the contract. The average increase in unit cost for labor was also impacted by lower sales volumes due to the economic environment as discussed above.

•

United Mine Workers of America (UMWA) health and retirement plan expenses have increased $0.30 per ton sold primarily due to the effects of the 2007 labor contract that require additional contributions to be made into employee benefit funds. The contribution increase over 2007 was $0.42 per United Mine Worker of America hour worked. The average increase in unit costs for health and retirement plans was also impacted by lower sales tons in the year-to-year comparison.

•

Subsidence cost increased $0.30 per ton sold primarily due to the year ended December 31, 2009 including additional expenses related to work to be performed on streams that have been impacted by underground mining in Pennsylvania. The average increase in unit costs for subsidence was also impacted by lower sales tons in the year-to-year comparison.

•

Other costs per unit on a net basis have increased $0.05 per ton sold due to various transactions that have occurred throughout both periods, none of which were individually material.

These increases in costs were offset, in part, by the following decrease:

•

Contract Mining Fees decreased $0.25 per ton sold due to lower contractor usage in the year ended December 31, 2009 compared to the year ended December 31, 2008.

Purchased coal cost of goods sold consists of costs from processing purchased coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased and sold directly to the customer and costs for processing third party coal in our preparation plants. The decrease of $78 million in purchased coal cost of goods sold and other charges in 2009 was primarily due to lower volumes purchased.

Gas cost of goods sold and other charges increased primarily due to a 24.3% increase in volumes of produced gas sold, offset, in part, by lower average cost per unit sold.


	2009		2008		Variance			Percentage Change
Produced Gas Sales Volumes (in billion cubic feet)		93.6		75.3		18.3		24.3	%
Average Cost per thousand cubic feet	$	2.36	$	2.51	$	(0.15	)	(6.0	)%

Average costs per unit decreased in the year ended December 31, 2009 as a result of several factors:

•

Well service costs have decreased by $0.07 per thousand cubic feet due to lower contract service rig hours needed as a result of less pump maintenance being required in 2009.

•

Gob collection charges were $0.04 per thousand cubic feet lower in the year-to-year comparison. Lower gob collection charges per unit were primarily due to the Buchanan longwall being idled throughout some of 2009.

•

Compression expenses decreased $0.03 per thousand cubic feet primarily due to a reduction in the number of compressors utilized in the Northern Appalachian production field. Due to the slow-down in the drilling program in Northern Appalachia, rented compressors have been returned to more appropriately design the gathering fields for existing needs.

•

Other costs have decreased $0.22 per thousand cubic feet primarily due to the impact of additional volumes of gas sold during the year ended December 31, 2009. Dollars spent remained consistent in the year-to-year comparisons, therefore additional volumes decreased the unit costs.

These decreases in unit costs were offset, in part, by the following:

•

Idle drilling costs were $0.09 per thousand cubic feet related to idling various drilling rigs throughout the company. Some of CNX Gas’ drilling contracts require minimum payments be made to the contracting party when drilling rigs are not being used. The CNX Gas drilling program has been slowed down pending a change in the economic environment. These charges resulted in an increase to costs.

•

Firm transportation costs increased $0.08 per thousand cubic feet primarily due to acquiring additional capacity in the Northern Appalachian region after December 31, 2008.

•

Power and fuel costs increased $0.04 per thousand cubic feet due to a power rate increase which occurred after December 31, 2008. Also, the increase was due to additional compressors being placed in service after December 31, 2008 along the existing gathering system in the Central Appalachian production field in order to flow the increasing gas volumes more efficiently.

Industrial supplies cost of goods sold decreased $1 million primarily due to decreased sales volumes.

Closed and idle mine cost of goods sold increased approximately $36 million in 2009 compared to 2008. Approximately $38 million of increased expenses were incurred at Mine 84 to pull underground equipment out of the mine in preparation of idling and to construct seals to close sections of the underground mine works so that the mine can be maintained in a more efficient manner. Increases were also attributable to the idled Shoemaker Mine incurring approximately $11 million of additional expenses in the current period related to the continued maintenance of the mine in an idled status. Closed and idle mine cost of goods sold also increased $7 million primarily due to the periodic idling of various other locations throughout 2009 due to the economic environment. These increases were offset, in part, by reductions of $20 million related to mine closing, reclamation and water treatment liabilities. These decreases primarily related to adjustments in engineering estimates of water quality and flows, as well as changes in the credit adjusted risk free interest rates.

Other cost of goods sold remained consistent due to the following items:


	2009		2008		Dollar Variance			Percentage Change
Incentive compensation	$	51	$	33	$	18		54.5	%
Legal settlement		15		—		15		100.0	%
Cease use expense		14		—		14		100.0	%
Dry hole and other costs		9		1		8		800.0	%
Stock-based compensation		38		34		4		11.8	%
Severance expense		4		—		4		100.0	%
Ward superfund site		3		7		(4	)	(57.1	)%
Sales contract buyout		13		19		(6	)	(31.6	)%
Profit splits		—		15		(15	)	(100.0	)%
Buchanan roof collapse		—		17		(17	)	(100.0	)%
Terminal/River operations		59		81		(22	)	(27.2	)%
Miscellaneous other		34		33		1		3.0	%

Other cost of goods sold and other charges	$	240	$	240	$	—		—

The incentive compensation program is designed to increase compensation to eligible employees when CONSOL Energy reaches predetermined production, safety and cost targets and the employees reach predetermined performance targets. Incentive compensation expense increased $18 million in 2009 due to exceeding the predetermined targets.

Legal settlement of $15 million represents the amount expensed for the settlement of the Levisa Action and the Pobst/Combs Action.

Approximately $14 million of cease use expense relates to the relocation of the CONSOL Energy and CNX Gas corporate office and the cease use of the old facilities. Accordingly, a liability for the present value of the remaining lease payments for the previous corporate offices has been recognized in Cost of Goods Sold and Other Charges and resulted in $14 million of expense.

Dry hole and other costs of $9 million were incurred by the gas segment in the year ended December 31, 2009. Dry hole and other costs were incurred in 2009 related to the determination that certain areas where an exploration well was drilled would not be economical to pursue. The costs for the exploration well, which were previously capitalized, were expensed. Other costs include costs associated with certain leased property that will no longer be held due to the determination that the area would not be economical to pursue. Also, costs related to particular permits for areas where management has determined that no drilling will take place have been expensed.

Stock-based compensation expense increased $4 million in the year-to-year comparison primarily due to $3 million of fair value adjustments associated with the exchange offer to convert CNX Gas performance share units into CONSOL restricted stock units. The year ended December 31, 2009 also includes additional expense due to expanding the stock-based compensation program to include additional employees. The year ended December 31, 2008 included a reduction to expense related to the CNX Gas performance share units to reflect the lower market price of CNX Gas shares at December 31, 2008 compared to its peer group. The CNX Gas performance share units were replaced with a CONSOL Energy restricted stock units in 2009.

Severance pay relates to the administrative staff reductions in force and resulted in $4 million of expense in 2009.

Ward transformer superfund site expense was $4 million lower in the year ended December 31, 2009 compared to the year ended December 31, 2008. The expense in each period represents CONSOL Energy’s portion of the latest estimate of cost to remediate the site. See “Note 24-Commitments and Contingencies” of Item 8 of the Consolidated Financial Statements for additional detail.

The year ended December 31, 2008 includes adjustments related to CONSOL Energy agreements to buy out coal sales contracts with several customers in order to release tons committed under lower priced contracts for sale to other customers at higher prices. The year ended December 31, 2009 includes fewer customer buyouts.

In the year ended December 31, 2008, cost of goods sold and other charges includes $15 million related to contracts with certain customers who were unable to take delivery of previously contracted coal tonnage. These customers agreed to allow CONSOL Energy to sell the released tonnage, but required CONSOL Energy to split the incremental sales price over the original contract sales price evenly with them. The $15 million represents the additional sales price received for the tonnage sold that is owed to the original customer.

Terminal/River operation charges have decreased approximately $22 million in the year-to-year comparison due to lower tonnage moved and lower employee counts throughout the year ended December 31, 2009.

Miscellaneous other cost of goods sold and other charges increased $1 million due to various transactions throughout both years, none of which were individually material.


	2009		2008		Variance			Percentage Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		9.8		8.5		1.3		15.3	%
Average Cost Per thousand cubic feet	$	3.30	$	8.69	$	(5.39	)	(62.0	)%

Purchased gas costs represent volumes of gas purchased from third party producers that we sell at market prices. Purchased gas cost volumes also reflect the impact of pipeline imbalances. The decrease in cost of goods sold and other charges related to purchased gas represents overall price changes and contractual differences among customers in the year-to-year comparison.


	2009		2008		Variance			Percentage Change
Purchased Gas Cost Volumes (in billion cubic feet)		1.7		1.0		0.7		70.0	%
Average Cost Per thousand cubic feet	$	3.75	$	8.13	$	(4.38	)	(53.9	)%

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 which CONSOL Energy contractually provides transportation services. Freight expense is the amount billed to customers for transportation costs incurred. Freight expense has decreased $69 million in the year ended December 31, 2009 primarily due to lower domestic shipments to customers whom CONSOL Energy pays the freight and then passes on the cost to the customer. Freight revenue also decreased due to fewer export sales made to customers whom CONSOL Energy pays the ocean-going freight and then passes the cost to the customer.

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


	2009		2008		Dollar Variance			Percentage Change
Rentals	$	9	$	3	$	6		200.0	%
Wages, salaries and related benefits		63		61		2		3.3	%
Association/charitable contributions		12		12		—		—
Advertising and promotion		5		6		(1	)	(16.7	)%
Professional, consulting and other purchased services		26		27		(1	)	(3.7	)%
Other		17		16		1		6.3	%

Total Selling, General and Administrative	$	132	$	125	$	7		5.6	%

Rentals have increased $6 million primarily due to rent expense related to the new CONSOL Energy headquarters, offset, in part, by reduced rent related to the previous CONSOL Energy and CNX Gas corporate office space that is no longer used.

Wages, salaries and related benefits have increased approximately $2 million primarily due to annual salary increases and additional recruiting expenses.

Association assessments and charitable contributions have remained consistent in the year-to-year comparison.

Advertising and promotion expenses have decreased $1 million in the year-to-year comparison due to the timing of various campaigns.

Costs of professional, consulting and other purchased services have decreased $1 million related to various corporate initiatives, none of which are individually material.

Other selling, general and administrative costs increased $1 million related to various transactions none of which are individually material.

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


	2009		2008		Dollar Variance		Percentage Change
Coal	$	307	$	299	$	8	2.7	%
Gas:
Production		86		51		35	68.6	%
Gathering		21		19		2	10.5	%

Total Gas		107		70		37	52.9	%
Other		23		21		2	9.5	%

Total Depreciation, Depletion and Amortization	$	437	$	390	$	47	12.1	%

The $8 million increase in coal depreciation, depletion and amortization was primarily attributable to assets placed in service during 2009.

The increase in gas production depreciation, depletion and amortization was primarily due to increased volumes produced, combined with an increase in the units of production rates for the Northern Appalachian region in the year-to-year comparison. These rates increased due to the higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. These rates are generally calculated using the net book value of assets at the end of the previous year divided by either proved or proved developed reserves. Production asset depreciation also increased due to the recalculation of rates in 2009 related to the Marcellus Shale wells and various other assets being placed in service during 2009.

Gas gathering depreciation, depletion and amortization is recorded using the straight-line method and increased $2 million in the year-to-year comparison due to various assets being placed in service during 2009.

Other depreciation increased $2 million in the year-to-year comparison due to various assets being placed in service during 2009, none of which were individually material.

Interest expense decreased in the year ended December 31, 2009 compared to the year ended December 31, 2008 due to the following items:


	2009			2008			Dollar Variance			Percentage Change
Revolver	$	6		$	11		$	(5	)	(45.5	)%
Interest on unrecognized tax benefits		2			2			—		—
Capitalized leases		6			6			—		—
Long-term secured notes		27			27			—		—
Other		(9	)		(10	)		1		(10.0	)%

Total Interest Expense	$	32		$	36		$	(4	)	(11.1	)%

Revolver interest expense is related to the amounts drawn on the credit facility. The decrease is related to lower interest rates on the facility in 2009 compared to 2008, offset, in part, by higher average amounts drawn in 2009.

Interest on unrecognized tax benefits, capitalize leases and long-term secured notes remained consistent in the year-to-year comparison.

Other interest expense increased $1 million in the year-to-year comparison due to various transactions that occurred throughout both periods, none of which were individually material.

Taxes other than income remained consistent in the year-to-year comparison.


	2009		2008		Dollar Variance			Percentage Change
Production taxes:
Coal	$	177	$	169	$	8		4.7	%
Gas		6		20		(14	)	(70.0	)%

Total Production Taxes		183		189		(6	)	(3.2	)%
Other taxes:
Coal		87		84		3		3.6	%
Gas		7		6		1		16.7	%
Other		13		11		2		18.2	%

Total Other Taxes		107		101		6		5.9	%

Total Taxes Other Than Income	$	290	$	290	$	—		—

Increased coal production taxes are primarily due to higher severance taxes attributable to the increase in average sales price for produced coal. These improvements were offset, in part, by lower coal production volumes in the year-to-year comparison.

Gas production taxes decreased $14 million due to lower severance taxes attributable to lower average sales prices for gas, offset, in part, by higher gas sales volumes. Lower severance taxes in the year-to-year comparison are also related to a revised estimate of a pending litigation settlement.

Other coal taxes have increased approximately $3 million primarily due to higher property taxes related to reassessments on property primarily in West Virginia and Pennsylvania owned by CONSOL Energy. The increase was also due to a reduction in the tax credit generated by production in the state of Virginia as a result of the idling of the longwall at the Buchanan Mine which reduced production during a portion of 2009.

Other gas taxes increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.

Other taxes have increased $2 million in the year-to-year comparison due to various transactions that occurred throughout both periods, none of which were individually material.

In 2008, $56 million of refunds related to black lung excise taxes were recognized. The refunds related to the Emergency Economic Stabilization Act of 2008 (the EESA Act) which was signed into law on October 3, 2008. The EESA Act contained a section that authorized certain coal producers and exporters who had filed a black lung excise tax (BLET) return on or after October 1, 1990, to request a refund of the BLET paid on export sales. The EESA Act required the U.S. Treasury to refund an amount equal to the BLET erroneously paid on export sales in prior years along with interest computed at the statutory rates applicable to overpayments. CONSOL Energy recognized, and subsequently received, approximately $56 million of BLET refunds. Approximately $1 million of additional interest income was recognized in 2009 to adjust estimated interest on these claims to the amount of interest received.

Income Taxes


	2009			2008			Variance			Percentage Change
Earnings Before Income Taxes	$	788		$	725		$	63		8.7	%
Income Tax Expense	$	221		$	240		$	(19	)	(7.9	)%
Effective Income Tax Rate		28.1	%		33.1	%		(5.0	)%

CONSOL Energy’s effective income tax rate is sensitive to changes to the relationship between pre-tax earnings and percentage depletion. The proportion of coal pre-tax earnings and gas pre-tax earnings also impacts the benefit of percentage depletion on the effective tax rate. See “Note 6—Income Taxes” in Item 8, Consolidated Financial Statements of this Form 10-K.

Noncontrolling Interest

Noncontrolling interest represents 16.7% of CNX Gas net income which CONSOL Energy does not own.

Results of Operations

Year Ended December 31, 2008 Compared with Year Ended December 31, 2007

Net Income

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


	2008			2007		Dollar Variance			Percentage Change
Sales Outside	$	4,182		$	3,324	$	858		25.8	%
Sales Purchased Gas		8			8		—		—
Sales Gas Royalty Interest		79			47		32		68.1	%
Freight—Outside		217			187		30		16.0	%
Other Income		166			196		(30	)	(15.3	)%

Total Revenue and Other Income		4,652			3,762		890		23.7	%
Coal Cost of Goods Sold and Other and Purchased Charges		2,843			2,351		492		20.9	%
Purchased Gas Costs		8			7		1		14.3	%
Gas Royalty Interest Costs		74			40		34		85.0	%

Total Cost of Goods Sold		2,925			2,398		527		22.0	%
Freight Expense		217			187		30		16.0	%
Selling, General and Administrative Expense		125			109		16		14.7	%
Depreciation, Depletion and Amortization		390			325		65		20.0	%
Interest Expense		36			31		5		16.1	%
Black Lung Excise Tax Refund		(56	)		24		(80	)	(333.3	)%
Taxes Other Than Income		290			259		31		12.0	%

Total Costs		3,927			3,333		594		17.8	%

Earnings Before Income Taxes and Minority Interest		725			429		296		69.0	%
Income Tax Expense		240			136		104		76.5	%

Earnings Before Minority Interest		485			293		192		65.5	%
Minority Interest		43			25		18		72.0	%

Net Income	$	442		$	268	$	174		64.9	%

CONSOL Energy had net income of $442 million for the year ended December 31, 2008 compared to $268 million in the year ended December 31, 2007. Net income for 2008 increased in comparison to 2007 due to:

•

higher average prices received for both coal and gas;

•

higher volumes of gas sold;

•

2007 included a total of approximately $94 million of pre-tax expenses, net of insurance recoveries, related to the Buchanan Mine incident that occurred in July 2007 which idled the mine through March 2008; the 2008 period includes approximately $28.6 million of pre-tax income related to this incident;

•

Black Lung excise tax refund receivable recognized for taxes paid in 1991-1993 due to legislation passed in October 2008; and

•

Receivable write off of $24 million in 2007 related to the Supreme Court decision which rendered the Black Lung Excise Tax receivable for 1991-1993 uncollectible.

These increases in net income were offset, in part, by:

•

an asset exchange and an asset sale in 2007 that resulted in pretax income of approximately $100 million and net income of approximately $59 million;

•

increased unit cost of goods sold and other charges for both coal and gas.

See below for a more detailed description of variances noted. The cost per unit below is not necessarily indicative of unit costs in the future.

Revenue

Revenue and other income increased due to the following items:


	2008		2007		Dollar Variance			Percentage Change
Sales:
Produced Coal	$	3,067	$	2,640	$	427		16.2	%
Purchased Coal		118		38		80		210.5	%
Produced Gas		681		410		271		66.1	%
Industrial Supplies		196		147		49		33.3	%
Other		120		89		31		34.8	%

Total Sales—Outside		4,182		3,324		858		25.8	%
Gas Royalty Interest		79		47		32		68.1	%
Purchased Gas		8		8		—		—
Freight Revenue		217		187		30		16.0	%
Other Income		166		196		(30	)	(15.3	)%

Total Revenue and Other Income	$	4,652	$	3,762	$	890		23.7	%

The increase in company produced coal sales revenue during 2008 was due to higher average prices, offset, in part, by slightly lower volumes of produced coal sold.


	2008		2007		Variance			Percentage Change
Produced Tons Sold (in millions)		64.3		64.8		(0.5	)	(0.8	)%
Average Sales Price Per Ton	$	47.66	$	40.74	$	6.92		17.0	%

The increase year-to-year in the average sales prices of coal was the result of global coal fundamentals being more favorable in 2008. Concerns regarding the adequacy of global supplies of coal had strengthened both the international and domestic coal prices and had increased the opportunity for U.S. producers to increase exports of coal. Sales tons were slightly lower in the year-to-year comparison.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased from third-parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants. The increase of $80 million in company-purchased coal sales revenue was primarily due to an increase in volumes of purchased coal sold in the year-to-year comparison.

The increase in produced gas sales revenue in 2008 compared to 2007 was primarily due to higher average sales prices and higher volumes of gas sold.


	2008		2007		Variance		Percentage Change
Produced Gas Sales Volumes (in billion cubic feet)		75.7		57.1		18.6	32.6	%
Average Sales Price Per thousand cubic feet	$	9.00	$	7.18	$	1.82	25.3	%

The increase in average sales price is the result of CNX Gas, an 83.3% subsidiary at December 31, 2008, realizing general market price increases in the year-to-year comparison. CNX Gas periodically enters 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 hedges represented approximately 43.4 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2008 at an average price of $9.25 per thousand cubic feet. In the prior year, these financial hedges represented approximately 18.4 billion cubic feet at an average price of $8.01 per thousand cubic feet. Sales volumes increased as a result of additional wells coming online from our on-going drilling program. Also, prior year sales volumes were impacted by the deferral of production at the Buchanan Mine.

The $49 million increase in revenues from the sale of industrial supplies was primarily due to the July 2007 acquisition of Piping & Equipment, Inc. in addition to an overall increase in sales volumes and higher sales prices.

The $31 million increase in other sales was attributable to increased revenues from barge towing and terminal services. The increase was primarily related to revenue generated from the barge towing operations having higher average rates for services rendered compared to the prior year. The barge towing operations have also increased thru-put tons and delivered tons in 2008. Increases in other sales revenues were also attributable to higher terminal services as a result of additional thru-put tons in 2008. The higher terminal revenues were offset, in part, due to services being suspended for approximately one month due to maintenance needed on a pier in Baltimore.


	2008		2007		Variance		Percentage Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		8.5		7.2		1.3	18.1	%
Average Sales Price Per thousand cubic feet	$	9.32	$	6.44	$	2.88	44.7	%

Gas royalty interest sales volumes represent the revenues related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The increase in market prices, contractual differences among leases and the mix of average and index prices used in calculating royalties contributed to the year-to-year change.


	2008		2007		Variance			Percentage Change
Purchased Sales Volumes (in billion cubic feet)		1.0		1.1		(0.1	)	(9.1	)%
Average Sales Price Per thousand cubic feet	$	8.76	$	7.19	$	1.57		21.8	%

Purchased gas sales volumes represent volumes of gas that were sold at market prices that were purchased from third-party producers, less gathering fees.

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. Freight revenue has increased $30 million in 2008 due primarily to freight associated with AMVEST, which was acquired on July 31, 2007. Freight revenue has also increased due to higher freight rates being charged for

exported tons. These increases in freight revenue were offset, in part, by lower export tons shipped in 2008 compared to 2007. There were 7.0 million tons and 7.6 million tons of coal exported by CONSOL Energy in 2008 and 2007, respectively.

Other income consists of interest income, gain or loss on the disposition of assets, equity in earnings of affiliates, service income, royalty income, derivative gains and losses, rental income and miscellaneous income.


	2008		2007		Dollar Variance			Percentage Change
Gain on sale of assets	$	23	$	112	$	(89	)	(79.5	)%
Interest income		2		13		(11	)	(84.6	)%
Litigation settlement		1		5		(4	)	(80.0	)%
Equity in earnings of affiliates		11		7		4		57.1	%
Railroad spur income		4		1		3		300.0	%
Proceeds from relinquishment of mining rights		6		—		6		100.0	%
Royalty income		21		14		7		50.0	%
Contract towing		11		3		8		266.7	%
Business interruption proceeds		50		10		40		400.0	%
Other miscellaneous		37		31		6		19.4	%

Total other income	$	166	$	196	$	(30	)	(15.3	)%

Gain on sale of assets decreased $89 million in the year-to-year comparison primarily due to two transactions that occurred in 2007. In June 2007, CONSOL Energy, through our 83.3% owned subsidiary, CNX Gas, exchanged certain coal assets in Northern Appalachia to Peabody Energy for coalbed methane and gas rights, which resulted in a pretax gain of $50 million. Also, in June 2007, CONSOL Energy, through a subsidiary, sold the rights to certain western Kentucky coal in the Illinois Basin to Alliance Resource Partners, L.P. for $53 million. This transaction also resulted in a pretax gain of approximately $50 million. The 2008 period reflects a sale of an idled facility which included the transfer of the mine closing liabilities to the buyer. This transaction resulted in a pretax gain of approximately $8 million. There was also a $3 million increase in the year-to-year comparison due to various transactions that occurred throughout both periods, none of which were individually material.

Interest income decreased $11 million in the year-to-year comparison due to lower cash balances throughout 2008 compared to 2007. Lower cash balances were primarily the result of the purchase price paid for the June 2008 acquisition of the remaining interest in Knox Energy, LLC, the July acquisition of several leases and gas wells from KIS Oil & Gas, Inc., the July 31, 2007 acquisition of AMVEST, the June 2007 purchase of certain coalbed methane and gas rights from Peabody Energy and the July 2007 Buchanan Mine incident.

A litigation settlement with a coal customer in 2007 resulted in $5 million of income. A litigation settlement with a royalty holder resulted in $1 million of income in 2008.

Equity in earnings of affiliates increased $4 million related to our interest in a specialty contracting company, our interest in a real estate development company and our interest in a coal mining company. These increases were offset, in part, by the June 2008 acquisition of our remaining interest in Knox Energy, LLC.

Income related to a railroad spur acquired with the July 2007 acquisition of AMVEST increased $3 million. This income was due to reimbursements from the rail carrier for maintenance completed on the spur during the year. The income is offset in its entirety with the related expenses reflected in cost of goods sold and other charges.

In 2008, approximately $6 million was received from a third party in order for CONSOL Energy to relinquish the mining of certain in-place coal reserves.

Royalty income increased $7 million in the year-to-year comparison due to production of CONSOL Energy coal by a third-party commencing in August 2007. Royalties have also increased due to the higher sales price of coal sold throughout 2008 compared to 2007.

The $8 million increase in contract towing services represents river towing services for third-parties which CONSOL Energy now provides. These services were minimal in 2007.

In 2008, CONSOL Energy received $50 million as final settlement of the insurance claim related to the July 2007 Buchanan Mine incident, which idled the mine from July 2007 to mid-March 2008. The $50 million represents business interruption coverage which was recognized in other income; the coal segment recognized $42 million and the gas segment recognized $8 million. CONSOL Energy had received $10 million of business interruption proceeds related to this incident in 2007; the coal segment recognized $8 million and the gas segment recognized $2 million. In 2007, $15 million was also received from the insurance carrier for reimbursement of fire brigade costs. This was recognized as a reduction of cost of goods sold and other charges as discussed below. The final settlement brought the total amount recovered from insurance carriers to $75 million, the maximum allowed per covered event. All proceeds from this insurance claim have been received.

Other miscellaneous income increased $6 million in the year-to-year comparison due to various miscellaneous transactions that occurred throughout both years, none of which were individually material.

Costs

Cost of goods sold and other charges increased due to the following:


	2008		2007		Dollar Variance			Percentage Change
Cost of Goods Sold and Other Charges
Produced Coal	$	2,031	$	1,685	$	346		20.5	%
Purchased Coal		124		52		72		138.5	%
Produced Gas		189		129		60		46.5	%
Industrial Supplies		186		141		45		31.9	%
Closed and Idle Mines		78		105		(27	)	(25.7	)%
Other		235		239		(4	)	(1.7	)%

Total Sales—Outside		2,843		2,351		492		20.9	%
Gas Royalty Interest		74		40		34		85.0	%
Purchased Gas		8		7		1		14.3	%

Total Cost of Goods Sold	$	2,925	$	2,398	$	527		22.0	%

Increased cost of goods sold and other charges for company-produced coal was due mainly to a higher average unit cost per ton sold, offset slightly by lower sales volumes.


	2008		2007		Variance			Percentage Change
Produced Tons Sold (in millions)		64.3		64.8		(0.5	)	(0.8	)%
Average Cost of Goods Sold and Other Charges Per Ton	$	31.57	$	25.99	$	5.58		21.5	%

Average cost of goods sold and other charges increased in the year-to-year comparison primarily due to an increase in average unit costs related to the following items.

•

Supply and maintenance costs have increased $2.77 per ton sold due to the following items:

•

The increase in supply and maintenance costs reflects the change in the mix of sales tons in 2008 compared to 2007. Production tons from the Northern Appalachian underground mines decreased, while production from the Central Appalachian mines increased. This was primarily due to the July 31, 2007 acquisition of AMVEST and to the Buchanan Mine being idled for half of 2007.

•

The installation of higher grade seals and a higher number of seals being built in 2008 contributed to the increase in supply cost. The Mine Health and Safety Administration now requires higher strength seals to be constructed in order to isolate old, abandoned areas or previously sealed areas of the mine. At several locations, the installed seals are also required to be stronger. The increase in strength of seals was required to better protect the active sections of the underground mines from explosions, fires, or other situations that may occur within the sealed areas. The installation of higher strength seals and a higher number of seals being completed contributed to the increase in supply costs.

•

Higher roof control costs are attributable to higher usage of products used in the mining process due to mining conditions and additional development work. Development work by continuous mining machines requires more roof support products than are used in the area of the mine where extraction is done using a longwall mining system. Roof control costs have also increased due to higher usage of “pumpable cribs” which are more expensive per unit than the standard wooden crib support. The “pumpable crib” is a canvas cylinder hung from the roof and extending to the floor into which concrete is pumped. Because the “pumpable crib” allows concrete to be pumped to the roof level, it eliminates the need to use wood shims to tighten the concrete to the roof. The “pumpable crib” is quicker to install, enhances safety due to the customized fit and minimizes the use of combustible products at underground locations. Also, roof control costs have increased due to approximately a 9% inflation rate related to roof control products.

•

Gas well plugging/drilling costs related to the mining process have increased in 2008 compared to 2007. Gas well plugging expenses are related to plugging abandoned gas wells which CONSOL Energy does not own that are in front of the underground mining process. These wells have to be plugged in accordance with current safety regulations in order to mine through. CONSOL Energy has plugged more wells in 2008 than in 2007, which has contributed to increased supply costs. Gas well drilling ahead of mining, vents the gas from the coal seam which then allows for the longwall process to extract coal from a ventilated seam. CONSOL Energy drilled more wells ahead of mining in 2008 than in 2007 primarily due to Buchanan Mine being idled for half of 2007, as previously discussed.

•

Higher fuel and explosive costs are due to the general increase of these commodities in the year-to-year comparison. The AMVEST surface locations were acquired on July 31, 2007. These surface locations are a large consumer of these products.

•

Higher equipment maintenance costs are also attributable to the acquisition of AMVEST on July 31, 2007.

•

These increases in supply costs were offset, in part, by expenses for self contained self rescuers which were purchased in 2007 in compliance with the Miner Act. There were fewer self-contained self rescuers purchased in 2008.

•

Labor costs have increased $1.14 per ton sold due to the effects of wage increases at the union and non-union mines from labor contracts which began in 2007. These contracts call for specified hourly wage increases in each year of the contract. Labor also increased due to a higher number of employees in 2008 compared to 2007. This was somewhat due to the utilization of new work schedules requiring more manpower and operations trainees.

•

Other postemployment benefit costs have increased $0.49 per ton sold primarily due to a change in the discount rate used to calculate the net periodic benefit costs. The weighted average discount rate for 2008 was 6.63% and was 6.00% in 2007.

•

Combined Fund costs have increased $0.33 per ton sold due to the 2007 settlement with the Fund. In March 2007, CONSOL Energy entered into a settlement agreement with the Combined Fund that resolved all previous issues relating to the calculation of the payments. The total income, including interest, as a result of this settlement was approximately $33.4 million, of which approximately $28.1 million impacted cost of goods sold and other charges for produced coal.

•

Health & Retirement costs have increased $0.25 per ton sold due to additional contributions required to be made into employee benefit funds in 2008 compared to 2007 as a result of the five-year labor agreement with the United Mine Workers of America (UMWA) that commenced January 1, 2007. The contribution increase over 2007 was $1.27 per UMWA hour worked.

•

In-transit costs have increased $0.25 per ton sold. In-transit costs are costs to move coal from the point of extraction to the preparation plant in order for the coal to be processed for sale. These costs have increased due primarily to increased trucking expenses related to higher fuel costs as well as several locations operating in the current year that did not operate in 2007.

•

Various other costs have increased $0.35 per ton sold due to various items that have occurred throughout both periods, none of which individually increased or decreased costs per ton sold.

Purchased coal cost of goods sold consists of costs from processing purchased coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased and sold directly to customers and costs for processing third-party coal in our preparation plants. The increase of $72 million in purchased coal cost of goods sold and other charges in 2008 was primarily due to higher volumes purchased.

Gas cost of goods sold and other charges increased due primarily to a 32.6% increase in volumes of produced gas sold and an 11.1% increase in unit costs of goods sold and other charges.


	2008		2007		Variance		Percentage Change
Produced Gas Sales Volumes (in billion cubic feet)		75.7		57.1		18.6	32.6	%
Average Cost Per thousand cubic feet	$	2.50	$	2.25	$	0.25	11.1	%

Average cost of goods sold and other charges per unit sold increased in the current year as a result of the following items:

•

Fuel and power increased $0.08 per thousand cubic feet for both lifting and gathering combined. This increase was primarily due to additional compressors being placed in service along the existing gathering systems in order to flow gas more efficiently.

•

Well closing costs increased $0.05 per thousand cubic feet in the year-to-year comparison. Well closing liabilities were adjusted in 2007 to reflect longer well lives than were previously estimated. This adjustment resulted in a reduction to expense. The adjustments to well closing liabilities were insignificant in 2008.

•

Water disposal costs have increased $0.05 per thousand cubic feet due to additional volumes of water produced by CNX Gas wells in 2008 compared to 2007.

•

Repairs and maintenance costs have increased $0.02 per thousand cubic feet due to higher material costs and higher contract labor costs.

•

Compression expenses increased $0.03 per thousand cubic feet due to the additional compressors discussed above.

•

Various other costs have also increased by $0.02 per thousand cubic feet for various items which occurred throughout both years, none of which were individually material.

Industrial supplies cost of goods sold increased $45 million primarily due to the July 2007 acquisition of Piping & Equipment, Inc. The increase was also related to additional volumes of goods sold and higher costs of good sold throughout 2008.

Closed and idle mine cost of goods sold decreased approximately $27 million in 2008 compared to 2007. The decrease was primarily due to $16 million of lower cost of goods sold and other charges at Shoemaker Mine. Shoemaker resumed longwall production in May 2008, but was idled throughout all of 2007. The decrease was

also related to updated engineering surveys related to mine closing, perpetual care water treatment and reclamation liabilities for closed and idled locations resulting in $23 million of expense in 2008 compared to $33 million of expense in 2007. The higher 2007 survey adjustments related primarily to perpetual water treatment changes in estimates of water flows and increased hydrated lime costs. Closed and idle mine cost of goods sold and other charges also increased $1 million due to various other charges which occurred throughout both periods, none of which were individually significant.

Other cost of goods sold decreased due to the following items:


	2008		2007		Dollar Variance			Percentage Change
Buchanan roof collapse	$	17	$	95	$	(78	)	(82.1	)%
Contract settlement		—		6		(6	)	(100.0	)%
Incentive compensation		33		35		(2	)	(5.7	)%
Ward superfund site		7		5		2		40.0	%
Accounts receivable securitization		6		3		3		100.0	%
Railroad spur expenses		4		1		3		300.0	%
Asset impairment		6		—		6		100.0	%
Stock-based compensation		34		24		10		41.7	%
Profit splits		15		—		15		100.0	%
Sales contract buy-outs		19		—		19		100.0	%
Terminal/River operations		81		58		23		39.7	%
Miscellaneous		13		12		1		8.3	%

Total of the Cost of Goods Sold and Other Charges	$	235	$	239	$	(4	)	(1.7	)%

In July 2007, production at the Buchanan Mine was suspended after several roof falls in previously mined areas damaged some of the ventilation controls inside the mine, requiring a general evacuation of the mine. In 2008, we have incurred approximately $17 million of cost of goods sold and other charges related to the Buchanan Mine event compared to $95 million in the prior year. The 2007 expense figure is net of $15 million related to insurance proceeds received as reimbursement for costs incurred under the policy. The mine resumed longwall production on March 17, 2008.

In 2007, CONSOL Energy agreed to a $6 million settlement for a contract violation with a customer.

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. Incentive compensation expense decreased $2 million due to the level of earnings in comparison to the predetermined performance target in the year-to-year comparison.

The year ended December 31, 2008 includes expense of $7 million related to the Ward Transformer superfund site. In 2008, revised estimates of total costs related to this site were received. The revised estimates indicate an increase in costs to remediate the site. The year ended December 31, 2007 includes $5 million of expense related to this site. See “Note 25—Commitments and Contingencies” of Item 8, of the Consolidated Financial Statements for more details.

Accounts receivable securitization fees increased $3 million in the year-to-year comparison. Higher amounts have been drawn under this program throughout 2008 compared to 2007.

Expenses increased $3 million in 2008 related to a railroad spur acquired with the July 2007 acquisition of AMVEST. The increase was related to maintenance completed on the spur during the year. These expenses are offset with the related income reflected in other income.

Asset impairment expenses of $6 million were recognized in 2008 primarily related to loans made to, and options to purchase shares of common stock, with a startup company whose efforts are to commercialize

technology to burn waste coal with near zero emissions to generate power. Due mainly to the downturn in the economy, it is not probable that the company can repay these loans, or that the company will complete a public offering. Therefore, the asset values have been written down.

Stock-based compensation expense increased $10 million primarily as a result of additional awards granted to CONSOL Energy and CNX Gas employees in 2008. In addition, stock-based compensation expense increased due to changes in expected value of the cash payout related to the performance share units of CNX Gas.

Cost of goods sold and other charges includes $15 million in 2008 related to contracts with certain customers which were unable to take delivery of previously contracted coal tonnage. These customers have agreed to allow CONSOL Energy to sell the released tonnage, but require CONSOL Energy to split the incremental sales price over the original contract sales price evenly with them. The $15 million represents the additional sales price received for the tonnage sold that is owed to the original customer.

In 2008, CONSOL Energy agreed 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 prices which resulted in $19 million of expense. No such agreements were made in 2007.

Terminal/River operation charges have increased $23 million in the year-to-year comparison due to increased fuel charges resulting from higher fuel prices and increased operating hours. Costs also have increased due to the acquisition of Tri-River Fleeting on October 3, 2007, as well as higher thru-put volumes in 2008.

Miscellaneous cost of goods sold and other charges increased $1 million due to various transactions throughout both periods, none of which were individually material.


	2008		2007		Variance		Percentage Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		8.5		7.2		1.3	18.1	%
Average Cost Per thousand cubic feet	$	8.69	$	5.52	$	3.17	57.4	%

Gas royalty interest costs represent the expenses related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The increase in volumes and price relates to the volatility and contractual differences among leases, as well as the mix of average and index prices used in calculating royalties.


	2008		2007		Variance			Percentage Change
Purchased Sales Volumes (in billion cubic feet)		1.0		1.1		(0.1	)	(9.1	)%
Average Cost Per thousand cubic feet	$	8.13	$	6.66	$	1.47		22.1	%

Purchased gas costs represent volumes of gas purchased from third-party producers, less our gathering and marketing fees, that we sell at market prices. Purchased gas volumes also include the impact of pipeline imbalances. The increase in cost of goods sold and other charges related to purchased gas represents overall price increases and contractual differences among customers in the year-to-year comparison.

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 which CONSOL Energy contractually provides transportation services. Freight expense is the amount billed to customers for transportation costs incurred. Freight expense has increased in 2008 due primarily to freight associated with AMVEST, which was acquired on July 31, 2007. Freight expense has also increased due to higher freight rates being charged for exported tons. These increases in freight expense were offset, in part, by lower export tons shipped in 2008 compared to 2007. There were 7.0 million tons and 7.6 million tons of coal exported by CONSOL Energy in 2008 and 2007, respectively.


	2008		2007		Dollar Variance		Percentage Change
Freight expense	$	217	$	187	$	30	16.0	%

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


	2008		2007		Dollar Variance			Percentage Change
Wages, salaries and related benefits	$	61	$	52	$	9		17.3	%
Association/charitable contributions		12		6		6		100.0	%
Advertising and promotion		6		4		2		50.0	%
Professional, consulting and other purchased services		27		29		(2	)	(6.9	)%
Other		19		18		1		5.6	%

Total Selling, General and Administrative	$	125	$	109	$	16		14.7	%

Wages, salaries and related benefits increased $9 million in the year-to-year comparison due to additional staffing at our CNX Gas subsidiary, additional administrative staffing acquired in the July 2007 Piping & Equipment acquisition and various other increases in support staff throughout CONSOL Energy.

Association assessments have increased $6 million in the year-to-year comparison due primarily to CONSOL Energy’s participation in an industry organization which has launched a program related to the promotion of coal as an energy solution. CONSOL Energy did not participate in this organization in 2007. Also, CONSOL Energy participates in various associations and contributes to various charities in an effort to support the professions and the communities in which we do business. The level of funding made to these organizations varies from year-to-year.

Advertising and promotion expenses increased $2 million in 2008 due to various additional advertising and promotion agreements entered into throughout the current year.

Costs of professional, consulting and other purchased services decreased $2 million due to various administrative projects throughout both years, none of which are individually material.

Other selling, general and administrative costs increased $1 million due to various transactions that have occurred throughout both years, none of which are individually material.

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


	2008		2007		Dollar Variance		Percentage Change
Coal	$	299	$	258	$	41	15.9	%
Gas:
Production		50		31		19	61.3	%
Gathering		20		18		2	11.1	%

Total Gas		70		49		21	42.9	%
Other		21		18		3	16.7	%

Total Depreciation, Depletion and Amortization	$	390	$	325	$	65	20.0	%

The increase in coal depreciation, depletion and amortization was primarily attributable to additional expense related to the assets purchased in the July 2007 acquisition of AMVEST. The increase was also attributable to assets placed in service after December 31, 2007.

The increase in gas production related depreciation, depletion and amortization was primarily due to higher volumes combined with an increase in the units of production rates in the year-to-year comparison. These rates increased due to the higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. These rates are generally calculated using the net book value of assets at the end of the previous year divided by either proved or proved developed reserves.

Gathering depreciation, depletion and amortization is recorded using the straight-line method and increased due to additional assets placed in service after December 31, 2007.

Other depreciation increased $3 million due to various items placed in service after December 31, 2007, none of which were individually material.

Interest expense increased in 2008 compared to 2007 due to the following items:


	2008			2007			Dollar Variance			Percentage Change
Revolver	$	11		$	5		$	6		120.0	%
Interest on unrecognized tax benefits		2			3			(1	)	(33.3	)%
Capitalized lease		6			7			(1	)	(14.3	)%
Long-term secured notes		27			28			(1	)	(3.6	)%
Other		(10	)		(12	)		2		(16.7	)%

Total Interest Expense	$	36		$	31		$	5		16.1	%

Revolver interest expense increased $6 million due to the amounts drawn by CONSOL Energy and CNX Gas on the credit facility throughout 2008. There were no amounts drawn until August 2007 on this facility by CONSOL Energy. CNX Gas had no amounts drawn throughout all of 2007. These increases were offset, in part, by lower interest rates in the year-to-year comparison.

Interest on uncertain tax benefits decreased $1 million due primarily to the settlement of various uncertain tax positions due to receipt of the audit report related to the years 2004-2005.

Interest on capital leases decreased $1 million due to the planned payments made on these leases after December 31, 2007.

Interest on long-term secured notes decreased $1 million due to the planned June 2007 principal payment on our $45 million secured note.

Other interest increased $2 million due primarily to lower amounts of interest capitalized in 2008 compared to 2007. Capitalized interest was lower in 2008 because capital expenditures which qualify for interest capitalization were lower. These lower expenditures were primarily related to the Robinson Run overland belt which was placed in service in September 30, 2007.

On October 3, 2008 the Emergency Economic Stabilization Act of 2008 (the EESA Act) was signed into law. The EESA Act contains a section that authorizes certain coal producers and exporters who have filed a Black Lung Excise Tax (BLET) return on or after October 1, 1990, to request a refund of the BLET paid on export sales. The EESA Act requires that the U.S. Treasury refund a coal producer or exporter an amount equal to the BLET erroneously paid on export sales in prior years along with interest computed at the statutory rates applicable to overpayments. CONSOL Energy filed timely claims for refunds under the EESA Act of the BLET with the Internal Revenue Service in the amount of approximately $27 million. In addition, the estimated interest related to the BLET refunds expected to be received is approximately $32 million. In relation to this receivable, CONSOL Energy also recognized approximately $3 million of expense that will be owed to third parties upon collection of the refunds. The year ended December 31, 2007 included a $24 million charge related to the reversal of the receivable that had been recognized in previous quarters related to the BLET refund. The Federal Circuit court had ruled that the damage claim for BLET paid for the period 1991-1993 be repaid. The Government appealed a similar case to the U.S. Supreme Court. On December 3, 2007 the United States Supreme Court granted the Government’s appeal to hear the case. The Supreme Court’s appeal of the petition made collection of the refund no longer highly probable because of the adverse ruling by the Supreme Court during 2007 under the statute on which our claim for this period was based. Accordingly, CONSOL Energy reversed the BLET receivable it had previously recognized.

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


	2008		2007		Dollar Variance			Percentage Change
Production taxes:
Coal	$	168	$	150	$	18		12.0	%
Gas		20		13		7		53.8	%

Total Production Taxes		188		163		25		15.3	%
Other taxes:
Coal		84		79		5		6.3	%
Gas		7		5		2		40.0	%
Other		11		12		(1	)	(8.3	)%

Total Other Taxes		102		96		6		6.3	%

Total Taxes Other Than Income	$	290	$	259	$	31		12.0	%

Coal production taxes increased $18 million due to higher severance taxes and reclamation fee taxes attributable to the increase in average sales price for produced coal. Coal production taxes also increased due to higher tons produced in 2008 than 2007.

Gas production taxes increased $7 million due to higher severance taxes attributable to higher average sales prices for gas and higher gas sales volumes.

The $5 million increase in other coal taxes is primarily due to higher payroll related taxes and higher property taxes. Higher payroll related taxes were the result of additional employees in 2008 and higher wages paid as discussed in the cost of goods sold and other cost section. Higher property taxes were related to additional properties acquired in the July 31, 2007 AMVEST acquisition, as previously disclosed.

Other gas taxes have increased $2 million primarily related to payroll taxes and capital stock & franchise taxes due to the on-going growth of the company.

Other taxes decreased $1 million due to various transactions that occurred throughout both years, none of which were individually material.

Income Taxes


	2008			2007			Variance			Percentage Change
Earnings Before Income Taxes	$	725		$	429		$	296		69.0	%
Tax Expense	$	240		$	136		$	104		76.5	%
Effective Income Tax Rate		33.1	%		31.7	%		1.4	%

CONSOL Energy’s effective tax rate is sensitive to changes in the relationship between pre-tax earnings and percentage depletion. The proportion of coal pre-tax earnings and gas pre-tax earnings also impacts the benefit of percentage depletion on the effective tax rate. See “Note 6—Income Taxes” in Item 8, Consolidated Financial Statements of this Form 10-K.

Noncontrolling Interest

Noncontrolling interest represents 18.3% of CNX Gas net income which CONSOL Energy did not own through September 30, 2008, 18.0% for October 2008, 16.9% for November 2008 and 16.7% for December 2008. The noncontrolling interest in CNX Gas has been changing due to the share repurchase program that was approved by the CONSOL Energy Board of Directors on October 21, 2008.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities in the consolidated financial statements and at the date of the financial statements. Note 1 of the Notes to the Audited Consolidated Financial Statements in this Annual Report on Form 10-K describes the significant accounting policies and methods used in the preparation of the Consolidated Financial Statements. On an on-going basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making the judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.

Other Post Employment Benefits

Certain subsidiaries of CONSOL Energy provide medical and life insurance benefits to retired employees not covered by the Coal Industry Retiree Health Benefit Act of 1992. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare. For salaried employees hired before January 1, 2007, the eligibility requirement is either age 55 with 20 years of service or age 62 with 15 years of service. Also, salaried employees and retirees contribute a target of 20% of the medical plan operating costs. Contributions may be higher, dependent on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared by CONSOL Energy and the participants based on their age and years of service at retirement. Annual cost increases in excess of 6% will be the responsibility of the participant. Any salaried or non-represented hourly employees that were hired or rehired effective January 1, 2007 or later will not become eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees will receive a retiree medical spending allowance of $2,250 per year for each year of service at retirement. Newly employed inexperienced employees represented by the United Mine Workers of America (UMWA), hired after January 1, 2007, will not be eligible to receive retiree benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked.

After our review, various actuarial assumptions, including discount rate, expected trend in health care costs, average remaining service period, average remaining life expectancy, per capita costs and participation level in each future year are used by our independent actuary to estimate the cost and benefit obligations for our retiree health plans. Most assumptions used in 2009 have not differed materially from the prior year actual experience. Expected trend in health care cost assumptions have been changed since the prior year. The initial expected trend in health care costs at this year’s measurement date, which was December 31, 2009, was 8.74% compared to a prior year expected 2009 trend in health care cost of 9.6%. In addition, the year the ultimate trend rate is reached was extended from 5.0% in 2015 to 4.50% in 2023. A 1.0% decrease in the health care trend rate would decrease interest and service cost for 2009 by approximately $17.0 million. A 1.0% increase in the health care trend rate would increase the interest and service cost by approximately $19.9 million. The discount rate is also determined each year at the measurement date. The discount rate is estimated by utilizing a corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody’s as of the measurement date. All future post employment benefit expected payments were discounted using a spot rate yield curve as of December 31, 2009. The appropriate discount rate was then selected from resulting discounted cash flows. For the years ended December 31, 2009 and 2008, the discount rate used to calculate the period end liability and the following year’s expense was 5.87% and 6.20%, respectively. A 0.25% increase in the discount rate would have decreased 2009 net periodic postretirement benefit costs by approximately $3.8 million. A 0.25% decrease in the discount rate would have increased 2009 net periodic postretirement benefit costs by approximately $3.8 million. Deferred gains and losses are primarily due to historical changes in the discount rate and medical cost inflation

differing from expectations in prior years. Changes to interest rates for the rates of returns on instruments that could be used to settle the actuarially determined plan obligations introduce substantial volatility to our costs. Accumulated actuarial gains or losses in excess of a pre-established corridor are amortized on a straight-line basis over the expected future service of active salary and non-represented employees to their assumed retirement age. At December 31, 2009 the average remaining service period is approximately 11 years for our non-represented plans. Accumulated actuarial gains or losses in excess of a pre-established corridor are amortized on a straight-line basis over the expected remaining life of our retired UMWA population. The average remaining service period of this population is not used for amortization purposes because the majority of the UMWA population of our plan is retired. At December 31, 2009, the average remaining life expectancy of our retired UMWA population used to calculate the following year’s expense is approximately 13 years.

The weighted average per capita costs used to value the December 31, 2009 Other Postretirement Benefit liability was 4.84% less than expected based on our trend assumption. This was due to more favorable experience during the year. If the actual change in per capita cost of medical services or other postretirement benefits are significantly greater or less than the projected trend rates, the per capita cost assumption would need to be adjusted, which could have a significant effect on the costs and liabilities recognized in the financial statements.

Significant increases in health and prescription drug costs for represented hourly retirees could have a material adverse effect on CONSOL Energy’s operating cash flow. However, the effect on CONSOL Energy’s cash flow from operations for salaried employees is limited to approximately 6% of the previous year’s medical cost for salaried employees due to the cost sharing provision in the benefit plan.

The estimated liability recognized in the December 31, 2009 financial statements was $2.8 billion. For the year ended December 31, 2009, we paid approximately $155.9 million for Other Postretirement Benefits, all of which were paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2009. CONSOL Energy does not expect to contribute to the other postretirement plan in 2010. We intend to pay benefit claims as they are due.

Salaried Pensions

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi–employer plans. The benefits for these plans are based primarily on years of service and employee’s pay near retirement. CONSOL Energy’s salaried plan allows for lump-sum distributions of benefits earned up until December 31, 2005, at the employees’ election. The Restoration Plan was frozen effective December 31, 2006 and was replaced prospectively with the CONSOL Energy Supplemental Retirement Plan. CONSOL Energy’s Restoration Plan allows only for lump-sum distributions earned up until December 31, 2006. Effective September 8, 2009, the Supplemental Retirement Plan was amended to include employees of CNX Gas.

In March of 2009 the CNX Gas defined benefit retirement plan was merged into the Consol Energy’s non-contributory defined benefit retirement plan. This change did not impact the benefits for employees of CNX Gas, an 83.3% owned subsidiary. CNX Gas employees hired after January 1, 2007, are not eligible to participate in this non-contributory defined benefit retirement plan. In lieu of participation in the non-contributory defined benefit plan, these employees began receiving an additional 3% company contribution into their defined contribution plan. CNX Gas employees who were hired prior to December 31, 2005 or who were employees of CONSOL Energy prior to this date were given a one-time opportunity to elect to remain in the defined benefit plan or opt to freeze their service accruals and participate in the additional 3% company contribution into their defined contribution plan.

Our independent actuaries calculate the actuarial present value of the estimated retirement obligation based on assumptions including rates of compensation, mortality rates, retirement age and interest rates. For the year ended December 31, 2009, compensation increases are assumed to range from 3% to 8% depending on age and

job classification. The discount rate is determined each year at the measurement date. The discount rate is estimated by utilizing a corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody’s as of the measurement date. All expected benefit payments from the CONSOL Energy retirement plan were discounted using a spot rate yield curve as of December 31, 2009. The appropriate equivalent discount rate was then selected for the resulting discounted pension cash flows. For the years ended December 31, 2009 and 2008, the discount rate used to calculate the period end liability and the following year’s expense was 5.79% and 6.28%, respectively. A 0.25% increase in the discount rate would have decreased the 2009 net periodic pension cost by $0.7 million. A 0.25% decrease in the discount rate would have increased the 2009 net periodic pension cost by $0.7 million. Deferred gains and losses are primarily due to historical changes in the discount rate and earnings on assets differing from expectations in prior years. At December 31, 2009 the average remaining service period is approximately 10 years. Changes to any of these assumptions introduce substantial volatility to our costs.

The market related asset value is derived by taking the cost value of assets as of December 31, 2009 and multiplying it by the average 36-month ratio of the market value of assets to the cost value of assets. CONSOL Energy’s pension plan weighted average asset allocations at December 31, 2009 consisted of 61% equity securities and 39% debt securities. The volatile economic environment and rapid deterioration in the equity markets have caused investment income and the value of investment assets held in our pension trust to decline and lose value. As a result, we may be required to increase the amount of cash contributions we make into the pension trust.

The estimated liability recognized in the December 31, 2009 financial statements was $192.0 million. For the year ended December 31, 2009, we contributed approximately $67.7 million for defined benefit retirement plans other than multi-employer plans. Our obligations with respect to these liabilities are partially funded at December 31, 2009. CONSOL Energy does expect to contribute to the defined benefit retirement plans during 2010. We intend to contribute an amount that will avoid benefit restrictions for the following plan year.

Workers’ Compensation and Coal Workers’ Pneumoconiosis

Workers’ compensation is a system by which individuals who sustain employment related physical injuries or some type of occupational diseases are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation. Workers’ compensation will also compensate the survivors of workers who suffer employment related deaths. The workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy records an actuarially calculated liability, which is determined using various assumptions, including discount rate, future healthcare cost trends, benefit duration and recurrence of injuries. The discount rate is determined each year at the measurement date. The discount rate is estimated by utilizing a corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody’s as of the measurement date. All future workers’ compensation expected benefit payments were discounted using a spot rate yield curve as of December 31, 2009. The appropriate equivalent discount rate was then selected from the resulting discounted workers’ compensation cash flows. For the years ended December 31, 2009 and 2008, the discount rate used to calculate the period end liability and the following year’s expense was 5.55% and 5.90%, respectively. A 0.25% increase or decrease in the discount rate would not have materially changed the 2009 workers’ compensation expense. Deferred gains and losses are primarily due to historical changes in the discount rates, several years of favorable claims experience, various favorable claims experience, various favorable state legislation changes and an overall lower incident rate than our assumptions. Accumulated actuarial gains or losses are amortized on a straight-line basis over the expected future benefit duration of current claimants. At December 31, 2009, the average expected benefit duration for this group is approximately 9 years. The estimated liability recognized in the financial statements at December 31, 2009 was approximately $179.3 million. CONSOL Energy’s policy has been to provide for workers’ compensation benefits from operating cash flow. For the year ended December 31, 2009, we made payments for workers’ compensation benefits and other related fees of approximately $37.6 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2009.

CONSOL Energy is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease. CONSOL Energy is also responsible under various state statutes for pneumoconiosis benefits. After our review, our independent actuaries calculate the actuarial present value of the estimated pneumoconiosis obligation based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and discount rates. The discount rate is determined each year at the measurement date. The discount rate is estimated by utilizing a corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody’s as of the measurement date. All future coal workers’ pneumoconiosis expected benefit payments were discounted using a spot rate yield curve at December 31, 2009. The appropriate equivalent discount rate was then selected from the resulting discounted coal workers’ pneumoconiosis cash flows. For the years ended December 31, 2009 and 2008, the discount rate used to calculate the period end liability and the following year’s expense was 5.84% and 6.23%, respectively. A 0.25% increase in the discount rate would have decreased 2009 coal workers’ pneumoconiosis expense by $0.7 million. A 0.25% decrease in the discount rate would have increased 2009 coal workers’ pneumoconiosis by $0.7 million. Actuarial gains associated with coal workers’ pneumoconiosis have resulted from numerous legislative changes over many years which have resulted in lower approval rates for filed claims than our assumptions originally reflected. Actuarial gains have also resulted from lower incident rates and lower severity of claims filed than our assumption originally reflected. The estimated liability recognized in the financial statements at December 31, 2009 was $194.6 million. For the year ended December 31, 2009, we paid coal workers’ pneumoconiosis benefits of approximately $10.7 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2009.

Reclamation, Mine Closure and Gas Well Closing Obligations

The Surface Mining Control and Reclamation Act established operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. CONSOL Energy accrues for the costs of current mine disturbance and final mine and gas well closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing liabilities, and gas well closing which are based upon permit requirements and CONSOL Energy engineering expertise related to these requirements, including the current portion, were approximately $533.2 million at December 31, 2009. This liability is reviewed annually by CONSOL Energy management and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental regulations change significantly.

Accounting for Asset Retirement Obligations requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate to the closure of mines and gas wells and the reclamation of land upon exhaustion of coal and gas reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the mine closing, reclamation and gas well closing liabilities. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.

Accounting for Asset Retirement Obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines.

Income Taxes

Deferred tax assets and liabilities are recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized.

All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2009, CONSOL Energy has deferred tax assets in excess of deferred tax liabilities of approximately $498.7 million. The deferred tax assets are evaluated periodically to determine if a valuation allowance is necessary.

Deferred tax valuation allowances increased $0.7 million in the year ended December 31, 2009 due to various transactions that occurred throughout 2009, none of which were individually material. Valuation allowances on certain net operating loss carry forwards were not released during the year due to negative evidence outweighing positive evidence indicating that these benefits will not be utilized in future years. CONSOL Energy continues to report a deferred tax asset of approximately $37.1 million relating to its state net operating loss carry forwards subject to a full valuation allowance. A review of positive and negative evidence regarding these benefits, primarily the history of financial and tax losses on a separate company basis, concluded that a full valuation allowance was warranted. The net operating loss carry forwards expire at various times from 2010 to 2027. A valuation allowance of $24.5 million has also been recorded against the state deferred tax asset attributable to future tax deductible differences for certain subsidiaries with histories of financial and tax losses. Management will continue to assess the realization of deferred tax assets attributable to state net operating loss carry forwards and future tax deductible differences based upon updated income forecast data and the feasibility of future tax planning strategies, and may record adjustments to valuation allowances against these deferred tax assets in future periods as appropriate that could materially impact net income.

CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement is determined. A previously recognized tax position is derecognized when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax liability. Actual results could differ from those estimates upon subsequent resolution of identified matters. Estimates of our uncertain tax liabilities, including interest and the current portion, were approximately $65.3 million at December 31, 2009.

Stock Based Compensation

As of December 31, 2009, we have issued three types of share based payment awards: options, restricted stock units, and performance share units. The Black-Scholes option pricing model is used to determine fair value of stock options at the grant date. Various inputs are utilized in the Black-Scholes pricing model, such as:

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stock price on measurement date,

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exercise price defined in the award,

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expected dividend yield based on historical trend of dividend payouts,

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risk-free interest rate based on a zero-coupon treasury bond rate,

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expected term based on historical grant and exercise behavior, and

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expected volatility based on historic and implied stock price volatility of CONSOL Energy stock and public peer group stock.

These factors can significantly impact the value of stock options expense recognized over the requisite service period of option holders.

The fair value of each restricted stock unit awarded is equivalent to the closing market price of a share of our company’s stock on the date of the grant. The fair value of each performance share unit is determined by the underlying share price of our company stock on the date of the grant and management’s estimate of the probability that the performance conditions required for vesting will be achieved.

As of December 31, 2009, $24.6 million of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.57 years. See Note 18 in the Notes to the Audited Consolidated Financial Statements in Item 8 in this Form 10-K for more information.

Contingencies

CONSOL Energy is currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for the resolution of these claims. This estimate has been developed in consultation with legal counsel involved in the defense of these matters and is based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Future results of operations for any particular quarter or annual period could be materially affected by changes in our assumptions or the outcome of these proceedings. See Note 24 in the Notes to the Audited Consolidated Financial Statements in Item 8 in this Form 10-K for more information.

Successful Efforts Accounting

We use the successful efforts method to account for our gas exploration and production activities. Under this method, cost of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. We use this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of our gas exploration and production activities.

Derivative Instruments

CNX Gas enters into financial derivative instruments to manage exposure to natural gas and oil price volatility. We measure every derivative instrument at fair value and record them on the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year. CNX Gas currently utilizes only cash flow hedges that are considered highly effective.

CNX Gas formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in fair values or cash flows of the hedge item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CNX Gas will discontinue hedge accounting prospectively.

Coal and Gas Reserve Values

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal and gas reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal and gas reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Our coal

reserves are periodically reviewed by an independent third party consultant. Our gas reserves 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;

•

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.

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal and gas attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. See “Risk Factors” in Item 1A of this report for a discussion of the uncertainties in estimating our reserves.

Liquidity and Capital Resources

CONSOL Energy generally has satisfied our working capital requirements and funded our capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. We utilize a $1 billion senior secured credit facility which expires in 2012. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in June 2012. The agreement provides for the release of collateral at the request of CONSOL Energy upon the achievement of certain credit ratings. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 4.50 to 1.00, measured quarterly. The interest coverage ratio was 24.78 to 1.00 at December 31, 2009. The facility also includes a maximum leverage ratio covenant of not more than 3.25 to 1.00, measured quarterly. The leverage ratio was 0.87 to 1.00 at December 31, 2009. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends and merge with another corporation. At December 31, 2009, the facility had approximately $415 million drawn and $268 million of letters of credit outstanding, leaving $317 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.

The Pennsylvania Department of Environmental Protection (PA DEP) and CONSOL Energy have executed a Consent Order and Agreement (the Agreement) that addresses financial assurance required by the State for CONSOL Energy’s Pennsylvania mine water treatment facilities for mines closed prior to August 1977. The Agreement requires the company to post approximately $34 million of financial assurance over a 10-year time frame. CONSOL Energy is evaluating use of the credit facility and other alternative sources to satisfy these requirements.

CONSOL Energy and certain of our U.S. subsidiaries also participate in a receivables securitization facility for the sale on a continuous basis of eligible trade accounts receivable that will provide, on a revolving basis, up to $165 million of short-term funding or letters of credit. CONSOL Energy formed CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, for the sole purpose of buying and selling eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL

Energy and certain subsidiaries, irrevocably and without recourse, sell all of their eligible trade accounts receivable to CNX Funding Corporation. CNX Funding Corporation then sells, on a revolving basis, an undivided percentage interest in the pool of eligible trade accounts receivable to financial institutions and their affiliates, while maintaining a subordinated interest in a portion of the trade receivables. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds is consistent with commercial paper rates plus a charge for administrative services paid to the financial institution. At December 31, 2009, eligible accounts receivable totaled approximately $151 million. There was $101 million of subordinate retained interest at December 31, 2009. Accounts receivable totaling $50 million were removed from the consolidated balance sheet at December 31, 2009. There were no letters of credit outstanding against the facility at December 31, 2009.

CNX Gas, an 83.3% consolidated subsidiary of CONSOL Energy, utilizes a revolving credit facility providing an initial aggregate outstanding principal amount of up to $200 million, including borrowings and letters of credit, which expires in October 2010. CNX Gas can request an additional $100 million increase in the aggregate outstanding principal amount. The agreement contains a negative pledge provision, pursuant to which CNX Gas assets cannot be used to secure other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, purchase or redeem CNX Gas stock, pay dividends and merge with another corporation. This facility includes a leverage ratio covenant of not more than 3.00 to 1.00, measured quarterly. This ratio was 0.38 to 1.00 at December 31, 2009. The facility also includes an interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 68.17 to 1.00 at December 31, 2009. At December 31, 2009, this facility had approximately $15 million of letters of credit issued and had approximately $58 million of outstanding borrowings, leaving approximately $127 million of unused capacity. As a result of the credit agreement, CNX Gas and their subsidiaries executed a Supplemental Indenture on October 21, 2005, guaranteeing CONSOL Energy’s 7.875% bonds.

Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. The risks include declines in our stock price, less availability and higher costs of additional credit streams, potential counterparty defaults, and further commercial bank failures. Although the majority of the financial institutions in our bank group appear to be strong, there are some that have been and could be considered take-over candidates. We have no indication that any such transactions would impact our current credit facility; however, the possibility does exist. Financial market disruptions may impact our collection of trade receivables. CONSOL Energy constantly monitors the creditworthiness of our customers. We believe that our current group of customers are sound and represent no abnormal business risk.

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

In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap transactions that qualify as financial cash flow hedge, which exist parallel to the underlying physical transactions. The fair value of these contracts was an asset of $117 million at December 31, 2009. The ineffective portion of these contracts was insignificant to earnings in the year ended December 31, 2009. Hedge counterparties consists of commercial banks who participate in the revolving credit facility. No issues related to our hedge agreements have been encountered to date.

CONSOL Energy frequently evaluates potential acquisitions. CONSOL Energy has funded acquisitions primarily with cash generated from operations and a variety of other sources, depending on the size of the

transaction, including debt financing. There can be no assurance that additional capital resources, including debt financing, will be available to CONSOL Energy on terms which CONSOL Energy finds acceptable, or at all.

Cash Flows (in millions)


	2009			2008			Change
Cash flows provided by operating activities	$	945		$	1,029		$	(84	)
Cash used in investing activities	$	(845	)	$	(1,099	)	$	254
Cash (used in) provided by financing activities	$	(173	)	$	166		$	(339	)

Cash flows provided by operating activities changed primarily due to the following items:

•

Operating cash flows were lower in 2009 due to $115 million of repayments on the accounts receivable securitization program compared to receipt of $40 million of proceeds in 2008.

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Operating cash flow in 2008 included a $75 million cash receipt from insurance carriers related to the Buchanan mine incident, as previously disclosed.

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Operating cash flows were lower in 2009 by approximately $26 million due to coal inventories. Coal inventories increased 1.5 million tons in 2009. Coal inventories increased 462 thousand tons in 2008.

•

Operating cash flow increased in 2009 due to higher net income in the year-to-year comparison. Net income included higher amounts of depreciation, depletion and amortization in 2009 as discussed in the year-to-year operation analysis. Operating cash flows also increased due to various other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years.

•

Operating cash flow increased in 2009 as the result of CONSOL Energy receiving the total principal and related interest for the Black Lung Excise Tax Refund, a total of $55 million, net of amounts paid to third parties.

Net cash used in investing activities changed primarily due to the following items:

•

Total capital expenditures decreased $142 million to $920 million in 2009 compared to $1,062 million in 2008. Capital expenditures for gas decreased $240 million due to the slow-down of the drilling program related to the weak economic environment and $36 million expended in 2008 for the acquisition of the remaining portion of Knox Energy, offset in part, by a $56 million increase due to Marcellus drilling activity in Northern Appalachia. Capital expenditures for coal and other activities increased $98 million due to various projects including the continued work at Shoemaker mine to replace the track haulage with belt haulage, the face extension work at Bailey mine, the purchase of longwall shields which were sold and leased back, and the Buchanan water handling system.

•

CONSOL Energy purchased $67 million of CNX Gas common stock on the open market during 2008. No purchases of CNX Gas stock were made during 2009.

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Proceeds from the sale of assets were $70 million in 2009 compared to $28 million in 2008. Proceeds in 2009 were primarily related to the sale of longwall equipment that was subsequently leased back. Proceeds in 2008 were primarily related to the sale of the Mill Creek Mine.

Net cash (used in) provided by financing activities changed primarily due to the following items:

•

In 2009, CONSOL Energy paid outstanding borrowings of $70 million to the revolving credit facility. In 2008, CONSOL Energy received approximately $237 million of proceeds from the revolving credit facility.

•

In 2009, CONSOL Energy’s 83.3% owned subsidiary, CNX Gas, repaid outstanding borrowings of $15 million to the revolving credit facility. In 2008, CNX Gas received proceeds of approximately $73 million from its revolving credit facility.

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CONSOL Energy repurchased $98 million of its common stock on the open market under the share repurchase program in 2008. No repurchases of common stock were made in 2009.

•

Tax benefits from stock-based compensation resulted in approximately $3 million of cash inflows in 2009. These benefits resulted in a cash inflow of approximately $22 million in 2008.

•

In 2009, $3 million of cash inflows were received related to the issuance of CONSOL Energy Treasury Stock compared to $15 million in 2008.

The following is a summary of our significant contractual obligations at December 31, 2009 (in thousands):

Payments due by Year


	Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Short-term Notes Payable	$	472,850	$	—	$	—	$	—	$	472,850
Purchase Order Firm Commitments		40,697		3,560		—		—		44,257
Gas Firm Transportation		28,531		52,120		49,934		303,347		433,932
Long-term Debt		39,024		338,401		5,421		20,358		403,204
Interest on Long-term Debt		27,204		35,192		1,589		24,549		88,534
Capital (Finance) Lease Obligations		6,370		10,953		8,717		39,512		65,552
Interest on Capital (Finance) Lease Obligations		4,627		7,665		6,470		10,867		29,629
Operating Lease Obligations		79,649		127,574		92,944		166,358		466,525
Other Long-term Liabilities(a)		398,907		564,488		570,559		2,482,146		4,016,100

Total Contractual Obligations(b)	$	1,097,859	$	1,139,953	$	735,634	$	3,047,137	$	6,020,583

(a)

Long-term liabilities include other post-employment benefits, work-related injuries and illnesses, mine reclamation and closure and other long-term liability costs. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2010 contributions are expected to approximate $64 million.

(b)	The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

Debt

At December 31, 2009, CONSOL Energy had total long-term debt of $468 million outstanding, including the current portion of long-term debt of $45 million. This long-term debt consisted of:

•

An aggregate principal amount of $249 million of 7.875% notes ($250 million of 7.875% notes due in March 2012, net of $1 million unamortized debt discount). The notes were issued at 99.174% of the principal amount. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and premium, if any, and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries. The notes are senior secured obligations and rank equally with all other secured indebtedness of the guarantors;

•

An aggregate principal amount of $31 million and $72 million of industrial revenue bonds which were issued to finance the Baltimore Port facility and bear interest at 6.50% per annum and mature in December 2010 and October 2011;

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$36 million in advance royalty commitments with an average interest rate of 10.4% per annum;

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An aggregate principal amount of $15 million on a variable rate note that bears interest at 6.10% at December 31, 2009. This note was incurred by a variable interest entity that is fully consolidated in which CONSOL Energy holds no ownership interest;

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An aggregate principal amount of $65 million of capital leases with a weighted average interest rate of 6.82% per annum;

At December 31, 2009, CONSOL Energy also had $415 million of aggregate principal amounts of outstanding borrowings and approximately $268 million of letters of credit outstanding under the $1 billion senior secured revolving credit facility.

At December 31, 2009, CNX Gas, an 83.3% owned subsidiary, had $58 million of aggregate principal amounts of outstanding borrowings and approximately $15 million of letters of credit outstanding under its $200 million revolving credit facility.

Total Equity and Dividends

CONSOL Energy had total equity of $2,024 million at December 31, 2009 and $1,674 million at December 31, 2008. Total equity increased primarily due to net income for the year ended December 31, 2009 and amortization of stock-based compensation awards. These increases were offset by changes in the actuarial long-term liabilities, changes in cash flow hedging, the declaration of dividends, and the issuance of treasury stock. See Consolidated Statements of Stockholders’ Equity in the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.

Total equity also changed due to the implementation of the Noncontrolling Interest Topic of the Financial Accounting Standards Board Accounting Standards Codification. This topic required minority interest to be recharacterized as noncontrolling interests, and classified as a component of equity for all periods presented as of January 1, 2009.

In September 2008, CONSOL Energy announced a share repurchase program of up to $500 million of the company’s common stock during a 24-month period beginning in September 2008. The share repurchase plan will be used from time-to-time depending on a number of factors including: current market conditions; the company’s financial outlook; business conditions, including cash flows and internal capital requirements; as well as alternative investment options. No shares have been purchased during 2009. As of December 31, 2008, we had purchased a total of 2,741,300 shares at an average price of $35.59 per share under this program.

Dividend information for the current year is as follows:


Declaration Date	Amount Per Share	Record Date	Payment Date
January 29, 2010	$0.10	February 9, 2010	February 19, 2010
October 23, 2009	$0.10	November 4, 2009	November 20, 2009
July 31, 2009	$0.10	August 6, 2009	August 24, 2009
April 24, 2009	$0.10	May 5, 2009	May 22, 2009
January 30, 2009	$0.10	February 9, 2009	February 20, 2009

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, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. Our credit facility limits our ability to pay dividends when our leverage ratio covenant is 2.50 to 1.00 or more or our availability is less than $100 million. The leverage ratio was 0.87 to 1.00 and our availability was approximately $317 million at December 31, 2009. The credit facility does not permit dividend payments in the event of default. There were no defaults in the year ended December 31, 2009.

Off-Balance Sheet Transactions

CONSOL Energy does not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s financial condition, changes in financial condition, revenues or expenses, results of

operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Consolidated Financial Statements. CONSOL Energy participates in various multi-employer benefit plans such as the United Mine Workers’ of America (UMWA) 1974 Pension Plan, the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at December 31, 2009. The various multi-employer benefit plans are discussed in Note 17-Other Employee Benefit Plans in Item 8 of this Form 10-K. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters of credit to secure our financial obligations for employee-related, environmental, deliveries and various other items which are not reflected on the balance sheet at December 31, 2009. Management believes these items will expire without being funded. See Note 24-Commitments and Contingent Liabilities in Item 8 of this Form 10-K.

Recent Accounting Pronouncements

In June 2009, the FASB issued authoritative guidance on the consolidation of variable interest entities, which is effective for CONSOL beginning July 1, 2010. The new guidance requires revised evaluations of whether entities represent variable interest entities, ongoing assessments of control over such entities, and additional disclosures for variable interests. We believe adoption of this new guidance will not have material impact on CONSOL’s financial statements.

In June 2009, the FASB issued accounting guidance regarding the accounting for transfers of financial assets that is designed to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The guidance enhances the information provided to financial statement users to provide greater transparency about transfers of financial assets and a transferor’s continuing involvement, if any, with transferred financial assets. The guidance requires enhanced disclosures about the risks that a transferor continues to be exposed to because of its continuing involvement in transferred financial assets. This guidance is effective for an entity’s first annual reporting period after November 15, 2009 and is not eligible for early adoption. Management believes that this guidance will result in the securitization facility transactions being reclassified from sales transactions to secured borrowing transactions as of January 1, 2010.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

In addition to the risks inherent in operations, CONSOL Energy is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CONSOL Energy’s exposure to the risks of changing natural gas prices, interest rates and foreign exchange rates.

CONSOL Energy is exposed to market price risk in the normal course of selling natural gas production and to a lesser extent in the sale of coal. CONSOL Energy sells coal under both short-term and long-term contracts with fixed price and/or indexed price contracts that reflect market value. CONSOL Energy uses fixed-price contracts, collar-price contracts and derivative commodity instruments that qualify as cash-flow hedges under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification to minimize exposure to market price volatility in the sale of natural gas. Our risk management policy prohibits the use of derivatives for speculative purposes.

CONSOL Energy has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base. All of the derivative instruments without other risk assessment procedures are held for purposes other than trading. They are used primarily to mitigate uncertainty and volatility and cover underlying exposures. CONSOL Energy’s market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.

CONSOL Energy believes that the use of derivative instruments, along with the risk assessment procedures and internal controls, mitigates our exposure to material risk. However, the use of derivative instruments without other risk assessment procedures could materially affect CONSOL Energy results of operations depending on interest rates or market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.

For a summary of accounting policies related to derivative instruments, see Note 1 of the Notes to the Consolidated Financial Statements in Item 8 of this Form 10-K.

Sensitivity analyses of the incremental effects on pre-tax income for the year ended December 31, 2009 of a hypothetical 10 percent and 25 percent change in natural gas prices for open derivative instruments as of December 31, 2009 are provided in the following table:

(a)

CONSOL Energy remains at risk for possible changes in the market value of these derivative instruments; however, such risk should be offset by price changes in the underlying hedged item. CONSOL Energy entered into derivative instruments to convert the market prices related portions of the 2010 through 2012 anticipated sales of natural gas to fixed prices. The sensitivity analyses reflect an inverse relationship between increases in commodity prices and a benefit to earnings. We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.

CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. All of the counterparties to CONSOL Energy’s natural gas derivative instruments also participate in CONSOL Energy’s revolving credit facility. The Company has not experienced any issues of non-performance by derivative counterparties. See “Liquidity and Capital Resources” for further discussion of current capital markets.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At December 31, 2009, CONSOL Energy had $468 million aggregate principal amount of debt outstanding under fixed-rate instruments and $473 million aggregate principal amount of debt outstanding under variable-rate instruments. CONSOL Energy’s primary exposure to market risk for changes in interest rates relates to our revolving credit facility, under which there were $415 million of borrowings outstanding at December 31, 2009. CONSOL Energy’s revolving credit facility bore interest at a weighted average rate of 1.05% per annum during the year ended December 31, 2009. A 100 basis-point increase in the average rate for CONSOL Energy’s revolving credit facility would not have significantly decreased net income for the period. CONSOL Energy’s 83.3% subsidiary, CNX Gas, also had outstanding borrowings under their revolving credit facility which bears interest at a variable rate. CNX Gas’ facility had outstanding borrowings of $58 million at December 31, 2009 and bore interest at a weighted average rate of 1.47% per annum during the year ended December 31, 2009. Due to the level of borrowings against this facility and the low weighted average interest rate in the year ended December 31, 2009, a 100 basis-point increase in the average rate for CNX Gas’ revolving credit facility would not have significantly decreased net income for the period.

Almost all of CONSOL Energy’s transactions are denominated in U.S. dollars, and, as a result, it does not have material exposure to currency exchange-rate risks.

Item 8.

Financial Statements and Supplementary Data.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Reports of Independent Registered Public Accounting Firms		100
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008 and 2007		102
Consolidated Balance Sheets at December 31, 2009 and 2008		103
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007		104
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007		105
Notes to Audited Consolidated Financial Statements		106

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of CONSOL Energy Inc.

We have audited the accompanying consolidated balance sheets of CONSOL Energy Inc. (and Subsidiaries) as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, and cash flows for the years then ended. Our audit also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CONSOL Energy Inc. (and Subsidiaries) at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements. As discussed in Note 15 to the consolidated financial statements, during the year ended December 31, 2008, the Company adopted the measurement provisions related to pension and other postretirement benefit obligations.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), CONSOL Energy, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 9, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 9, 2010

100

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of CONSOL Energy Inc.:

In our opinion, the consolidated statements of income, stockholders’ equity and cash flows for the year ended December 31, 2007 present fairly, in all material respects, the results of CONSOL Energy Inc. and its subsidiaries (CONSOL Energy) operations and their cash flows for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule included in Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of CONSOL Energy’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, CONSOL Energy changed the manner in which it accounts for non-controlling interests effective January 1, 2009.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 18, 2008, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the change in accounting for non-controlling interests discussed in Note 1 to the consolidated financial statements, as to which the date is June 26, 2009.

101

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)


	For the Years Ended December 31,
	2009			2008			2007
Sales—Outside	$	4,311,791		$	4,181,569		$	3,324,346
Sales—Purchased Gas		7,040			8,464			7,628
Sales—Gas Royalty Interests		40,951			79,302			46,586
Freight—Outside		148,907			216,968			186,909
Other Income (Note 3)		113,186			166,142			196,728

Total Revenue and Other Income		4,621,875			4,652,445			3,762,197
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)		2,757,052			2,843,203			2,352,000
Purchased Gas Costs		6,442			8,175			7,162
Gas Royalty Interests Costs		32,376			73,962			39,921
Freight Expense		148,907			216,968			186,909
Selling, General and Administrative Expenses		130,704			124,543			108,664
Depreciation, Depletion and Amortization		437,417			389,621			324,715
Interest Expense (Note 4)		31,419			36,183			30,851
Taxes Other Than Income (Note 5)		289,941			289,990			258,926
Black Lung Excise Tax Refund		(728	)		(55,795	)		24,092

Total Costs		3,833,530			3,926,850			3,333,240

Earnings Before Income Taxes		788,345			725,595			428,957
Income Taxes (Note 6)		221,203			239,934			136,137

Net Income		567,142			485,661			292,820
Less: Net Income Attributable to Noncontrolling Interest		(27,425	)		(43,191	)		(25,038	)

Net Income Attributable to CONSOL Energy Inc. Shareholders	$	539,717		$	442,470		$	267,782

Earnings Per Share (Note 1):
Basic	$	2.99		$	2.43		$	1.47

Dilutive	$	2.95		$	2.40		$	1.45

Weighted Average Number of Common Shares Outstanding (Note 1):
Basic		180,693,243			182,386,011			182,050,627

Dilutive		182,821,136			184,679,592			184,149,751

Dividends Paid Per Share	$	0.40		$	0.40		$	0.31

The accompanying notes are an integral part of these consolidated financial statements.

102

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)


	December 31,
	2009			2008
ASSETS
Current Assets:
Cash and Cash Equivalents	$	65,607		$	138,512
Accounts and Notes Receivable:
Trade		317,460			221,729
Other Receivables		15,983			79,552
Inventories (Note 8)		307,597			227,810
Recoverable Income Taxes		—			33,862
Deferred Income Taxes (Note 6)		73,383			60,599
Prepaid Expenses		161,006			221,750

Total Current Assets		941,036			983,814

Property, Plant and Equipment:
Property, Plant and Equipment		10,681,955			9,980,288
Less—Accumulated Depreciation, Depletion and Amortization		4,557,665			4,214,316

Total Property, Plant and Equipment—Net (Note 10)		6,124,290			5,765,972

Other Assets:
Deferred Income Taxes (Note 6)		425,297			333,543
Investment in Affiliates		83,533			72,996
Other		151,245			214,133

Total Other Assets		660,075			620,672

TOTAL ASSETS	$	7,725,401		$	7,370,458

LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	269,560		$	385,197
Short-Term Notes Payable (Note 11)		472,850			557,700
Current Portion of Long-Term Debt (Note 13 and Note 14)		45,394			22,401
Accrued Income Taxes		27,944			—
Other Accrued Liabilities (Note 12)		612,838			546,442

Total Current Liabilities		1,428,586			1,511,740

Long-Term Debt:
Long-Term Debt (Note 13)		363,729			393,312
Capital Lease Obligations (Note 14)		59,179			75,039

Total Long-Term Debt		422,908			468,351

Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions (Note 15)		2,679,346			2,493,344
Pneumoconiosis Benefits (Note 16)		184,965			190,261
Mine Closing		397,320			404,629
Gas Well Closing		85,992			80,554
Workers’ Compensation (Note 16)		152,486			128,477
Salary Retirement (Note 15)		189,697			194,567
Reclamation		27,105			38,193
Other		132,517			185,996

Total Deferred Credits and Other Liabilities		3,849,428			3,716,021

TOTAL LIABILITIES		5,700,922			5,696,112

Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 183,014,426 Issued and 181,086,267 Outstanding at December 31, 2009; 183,014,426 Issued and 180,549,851 Outstanding at December 31, 2008		1,830			1,830
Capital in Excess of Par Value		1,033,616			993,478
Preferred Stock, 15,000,000 authorized, None issued and outstanding		—			—
Retained Earnings		1,456,898			1,010,902
Accumulated Other Comprehensive Loss (Note 19)		(640,504	)		(461,900	)
Common Stock in Treasury, at Cost—1,928,159 Shares at December 31, 2009 and 2,464,575 Shares at December 31, 2008		(66,292	)		(82,123	)

Total CONSOL Energy Inc. Stockholders’ Equity		1,785,548			1,462,187

Noncontrolling Interest		238,931			212,159

TOTAL EQUITY		2,024,479			1,674,346

TOTAL LIABILITIES AND EQUITY	$	7,725,401		$	7,370,458

The accompanying notes are an integral part of these consolidated financial statements.

103

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands, except per share data)


	Common Stock			Capital in Excess of Par Value			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Common Stock in Treasury			Total CONSOL Energy, Inc. Stockholders’ Equity			Non- Controlling Interest			Total Equity
Balance at December 31, 2006	$	1,851		$	921,881		$	600,541		$	(375,717	)	$	(82,405	)	$	1,066,151		$	135,659		$	1,201,810
Net Income		—			—			267,782			—			—			267,782			25,038			292,820
Treasury Rate Lock (Net of $52 Tax)		—			—			—			(81	)		—			(81	)		—			(81	)
Gas Cash Flow Hedge (Net of $2,146 Tax)		—			—			—			3,445			—			3,445			769			4,214
Actuarially Determined Long-Term Liability Adjustments (Net of $27,991 Tax)		—			—			—			(46,931	)		—			(46,931	)		(78	)		(47,009	)

Comprehensive Income (Loss)		—			—			267,782			(43,567	)		—			224,215			25,729			249,944
Cumulative Effect of Adoption of Income Tax Uncertainties		—			—			(3,202	)		—			—			(3,202	)		—			(3,202	)
Issuance of Treasury Stock		—			—			(42,110	)		—			61,334			19,224			—			19,224
Issuance of CNX Gas Stock		—			—			—			—			—			—			215			215
Purchases of Treasury Stock		—			—			—			—			(80,157	)		(80,157	)		—			(80,157	)
Purchases of CNX Gas Stock		—			—			—			—			—			—			(1,762	)		(1,762	)
Tax Benefit From Stock-Based Compensation		—			23,682			—			—			—			23,682			16			23,698
Amortization of Stock-Based Compensation Awards		—			20,981			—			—			—			20,981			3,261			24,242
Dividends ($0.31 per share)		—						(56,475	)		—			—			(56,475	)		—			(56,475	)

Balance at December 31, 2007		1,851			966,544			766,536			(419,284	)		(101,228	)		1,214,419			163,118			1,377,537
Net Income		—			—			442,470			—			—			442,470			43,191			485,661
Treasury Rate Lock (Net of $55 Tax)		—			—			—			(77	)		—			(77	)		—			(77	)
Gas Cash Flow Hedge (Net of $77,292 Tax)		—			—			—			97,833			—			97,833			20,813			118,646
Actuarially Determined Long-Term Liability Adjustments (Net of $82,156 Tax)		—			—			—			(140,289	)		—			(140,289	)		(16	)		(140,305	)

Comprehensive Income (Loss)		—			—			442,470			(42,533	)		—			399,937			63,988			463,925
Adoption of Actuarially Determined Long-Term Liability Measurement Provision (Net of $23,652 Tax)		—			—			(38,606	)		(83	)		—			(38,689	)		(18	)		(38,707	)
Issuance of Treasury Stock		—			—			(21,519	)		—			34,980			13,461			—			13,461
Issuance of CNX Gas Stock		—			—			—			—			—			—			312			312
Purchases of Treasury Stock		—			—			—			—			(15,875	)		(15,875	)		—			(15,875	)
Purchases of CNX Gas Stock		—			—			—			—			—			—			(18,682	)		(18,682	)
Retirement of Common Stock (2,112,200 Shares)		(21	)		(16,876	)		(65,022	)		—			—			(81,919	)		—			(81,919	)
Tax Benefit From Stock-Based Compensation		—			22,003			—			—			—			22,003			62			22,065
Amortization of Stock-Based Compensation Awards		—			21,807			—			—			—			21,807			3,379			25,186
Dividends ($0.40 per share)		—			—			(72,957	)		—			—			(72,957	)		—			(72,957	)

Balance at December 31, 2008		1,830			993,478			1,010,902			(461,900	)		(82,123	)		1,462,187			212,159			1,674,346
Net Income		—			—			539,717			—			—			539,717			27,425			567,142
Treasury Rate Lock (Net of $49 Tax)		—			—			—			(83	)		—			(83	)		—			(83	)
Gas Cash Flow Hedge (Net of $34,932 Tax)		—			—			—			(44,270	)		—			(44,270	)		(8,862	)		(53,132	)
Actuarially Determined Long-Term Liability Adjustments (Net of $77,361 Tax)		—			—			—			(134,251	)		—			(134,251	)		(298	)		(134,549	)

Comprehensive Income (Loss)		—			—			539,717			(178,604	)		—			361,113			18,265			379,378
Issuance of Treasury Stock		—			—			(21,429	)		—			15,831			(5,598	)		—			(5,598	)
Issuance of CNX Gas Stock		—			—			—			—			—			—			157			157
Tax Benefit From Stock-Based Compensation		—			2,674			—			—			—			2,674			13			2,687
Amortization of Stock-Based Compensation Awards		—			32,723			—			—			—			32,723			16,658			49,381
Stock-Based Compensation Awards to CNX Gas Employees		—			4,741			—			—			—			4,741			(3,951	)		790
Net Change in Crown Drilling Noncontrolling Interest		—			—			—			—			—			—			(4,370	)		(4,370	)
Dividends ($0.40 per share)		—			—			(72,292	)		—			—			(72,292	)		—			(72,292	)

Balance at December 31, 2009	$	1,830		$	1,033,616		$	1,456,898		$	(640,504	)	$	(66,292	)	$	1,785,548		$	238,931		$	2,024,479

The accompanying notes are an integral part of these consolidated financial statements.

104

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

(Dollars in thousands, except per share data)


	For the Years Ended December 31,
	2009			2008			2007
Cash Flows from Operating Activities:
Net Income	$	567,142		$	485,661		$	292,820
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization		437,417			389,621			324,715
Stock-based Compensation		39,032			25,186			24,243
Gain on Sale of Assets		(15,121	)		(23,368	)		(112,389	)
Amortization of Mineral Leases		3,970			4,871			4,519
Deferred Income Taxes		47,430			135,594			59,555
Equity in Earnings of Affiliates		(15,707	)		(11,140	)		(6,551	)
Changes in Operating Assets:
Accounts Receivable Securitization		(115,000	)		39,600			125,400
Accounts and Notes Receivable		84,597			(79,747	)		14,074
Inventories		(79,787	)		(53,994	)		13,448
Prepaid Expenses		10,730			(5,032	)		(9,145	)
Changes in Other Assets		(724	)		17,081			40,164
Changes in Operating Liabilities:
Accounts Payable		(70,458	)		64,851			(2,435	)
Other Operating Liabilities		80,527			(14,020	)		(30,978	)
Changes in Other Liabilities		(45,883	)		51,546			(54,924	)
Other		17,286			2,754			1,517

Net Cash Provided by Operating Activities		945,451			1,029,464			684,033

Cash Flows from Investing Activities:
Capital Expenditures		(920,080	)		(1,061,669	)		(743,114	)
Acquisition of AMVEST		—			—			(296,724	)
Proceeds from Sale of Assets		69,884			28,193			84,791
Purchase of Stock in Subsidiary		—			(67,259	)		(10,000	)
Net Investment in Equity Affiliates		4,855			1,879			(7,057	)

Net Cash Used in Investing Activities		(845,341	)		(1,098,856	)		(972,104	)

Cash Flows from Financing Activities:
Payments on Long-Term Debt		—			—			(45,000	)
(Payments on) Proceeds from Short-Term Debt		(84,850	)		310,200			247,500
Payments on Miscellaneous Borrowings		(19,190	)		(10,414	)		(2,935	)
Tax Benefit from Stock-Based Compensation		3,270			22,003			23,682
Dividends Paid		(72,292	)		(72,957	)		(56,475	)
Issuance of Treasury Stock		2,547			15,215			19,224
Purchases of Treasury Stock		—			(97,794	)		(80,157	)
Noncontrolling Interest Member Distribution		(2,500	)		—			—

Net Cash (Used In) Provided By Financing Activities		(173,015	)		166,253			105,839
Net Increase (Decrease) in Cash and Cash Equivalents		(72,905	)		96,861			(182,232	)
Cash and Cash Equivalents at Beginning of Period		138,512			41,651			223,883

Cash and Cash Equivalents at End of Period	$	65,607		$	138,512		$	41,651

The accompanying notes are an integral part of these consolidated financial statements.

See Note 20—Supplemental Cash Flow

105

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 1—Significant Accounting Policies:

A summary of the significant accounting policies of CONSOL Energy Inc. and subsidiaries (CONSOL Energy) is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements.

Basis of Consolidation:

The Consolidated Financial Statements include the accounts of majority-owned and controlled subsidiaries. The accounts of variable interest entities (VIEs) as defined by the Consolidation Topic of the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification where CONSOL Energy is the primary beneficiary, are included in the consolidated financial statements. Investments in business entities in which CONSOL Energy does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation.

Use of Estimates:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates. The most significant estimates included in the preparation of the financial statements are related to other postretirement benefits, coal workers’ pneumoconiosis, workers’ compensation, salary retirement benefits, stock-based compensation, reclamation, mine closure and gas well plugging liabilities, deferred income tax assets and liabilities, contingencies, and coal and gas reserve values.

Cash and Cash Equivalents:

Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.

Trade Accounts Receivable:

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CONSOL Energy reserves for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. CONSOL Energy regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Reserves for uncollectible amounts were not material in the periods presented.

Inventories:

Inventories are stated at the lower of cost or market. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead and other related costs. The cost of merchandise for resale is determined by the last-in, first-out (LIFO) method and includes industrial maintenance, repair and operating supplies for sale to third parties. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in our mining operations.

106

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Property, Plant and Equipment:

Property, plant and equipment is carried at cost. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Costs of additional mine facilities required to maintain production after a mine reaches the production stage, generally referred to as “receding face costs,” are expensed as incurred; however, the costs of additional airshafts and new portals are capitalized. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred.

Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore or minerals before beginning the development stage of the mine.

Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which are costs incurred to make the mineral physically accessible, include costs to prepare property for shafts, driving main entries for ventilation, haulage, personnel, construction of airshafts, roof protection and other facilities. Costs of developing the first pit within a permitted area of a surface mine are capitalized. A surface mine is defined as the permitted mining area which includes various adjacent pits that share common infrastructure, processing equipment and a common ore body. Surface mine development costs include construction costs for entry roads, drilling, blasting and removal of overburden in developing the first cut for mountain stripping or box cuts for surface stripping. Stripping costs incurred during the production phase of a mine are expensed as incurred.

Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production using the units-of-production method. Depletion of leased coal interests is computed using the units-of-production method over proven and probable coal reserves. Advance mining royalties and leased coal interests are evaluated periodically for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.

When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized in other income.

Gas wells are accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, but at least once a year; those revisions are accounted for prospectively as changes in accounting estimates.

Depreciation of mining plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows:


		Years
Building and improvements		10 to 45
Mine machinery and equipment		3 to 25
Leasehold improvements		Life of Lease

107

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Costs to obtain coal lands are capitalized based on the fair value at acquisition and are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned and accessible to the mine. Proven and probable coal reserves exclude non-recoverable coal reserves and anticipated processing losses. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is produced. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material income effect from changes in estimates is disclosed in the period the change occurs.

Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material income effect from changes in estimates is disclosed in the period the change occurs. Amortization of development cost begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.

Costs for purchased and internally developed software are expensed until it has been determined that the software will result in probable future economic benefits and management has committed to funding the project. Thereafter, all direct costs of materials and services incurred in developing or obtaining software, including certain payroll and benefit costs of employees associated with the project, are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed 7 years.

Impairment of Long-lived Assets:

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the assets’ carrying value. Impairment expense of $4,211 was recognized in Cost of Goods Sold and Other Operating Charges for the year ended December 31, 2009 for the impairment of certain sales contract assets. Impairment expense of $3,773 was recognized in Cost of Goods Sold and Other Operating Charges in December 2008, when it became probable that an option to purchase preferred equity in PFBC Environment Energy Technology would not be exercised.

Income Taxes:

Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in CONSOL Energy’s financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of CONSOL Energy’s assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized.

108

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

As required by the Income Tax Topic of the FASB Accounting Standards Codification, CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement, is determined. A previously recognized tax position is derecognized when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution of identified matters.

Postretirement Benefits Other Than Pensions:

Postretirement benefits other than pensions, except for those established pursuant to the Coal Industry Retiree Health Benefit Act of 1992 (the Health Benefit Act), are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the FASB Accounting Standards Codification which requires employers to accrue the cost of such retirement benefits for the employees’ active service periods. Such liabilities are determined on an actuarial basis and CONSOL Energy is primarily self-insured for these benefits. Postretirement benefit obligations established by the Health Benefit Act are treated as a multi-employer plan which requires expense to be recorded for the associated obligations as payments are made. This treatment is in accordance with the Retirement Benefits Compensation (Extractive Activities—Mining) Topic of the FASB Accounting Standards Codification.

Pneumoconiosis Benefits and Workers’ Compensation:

CONSOL Energy is required by federal and state statutes to provide benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers’ pneumoconiosis. CONSOL Energy is also required by various state statutes to provide workers’ compensation benefits for employees who sustain employment related physical injuries or some types of occupational disease. Workers’ compensation benefits include compensation for their disability, medical costs, and on some occasions, the cost of rehabilitation. CONSOL Energy is primarily self-insured for these benefits. Provisions for estimated benefits are determined on an actuarial basis.

Mine Closing, Reclamation and Gas Well Closing:

CONSOL Energy accrues for reclamation costs, mine closing costs, perpetual water care costs and dismantling and removing costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Depreciation of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in the Cost of Goods Sold and Other Operating Charges line on the Consolidated Statements of Income. Asset retirement obligations primarily relate to the closure of mines and gas wells, and includes treatment of water and the reclamation of land upon exhaustion of coal and gas reserves.

109

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Accrued mine closing costs, perpetual care costs, reclamation and costs of dismantling and removing gas related facilities are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements.

Retirement Plans:

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer retirement plans. Effective January 1, 2007, employees hired by CNX Gas, an 83.3% owned subsidiary, will not be eligible to participate in the non-contributory defined benefit retirement plan. In lieu of participation in this plan, these employees began receiving an additional 3% company contribution into their defined contribution plan.

Revenue Recognition:

Revenues are recognized when title passes to the customers. For domestic coal sales, this generally occurs when coal is loaded at mine or offsite storage locations. For export coal sales, this generally occurs when coal is loaded onto marine vessels at terminal locations. For gas sales, this occurs at the contractual point of delivery. For industrial supplies and equipment sales, this generally occurs when the products are delivered. For terminal, river and dock, land, research and development, and coal waste disposal services, revenue is recognized generally as the service is provided to the customer.

CNX Gas has operational gas-balancing agreements with various interstate pipelines. These imbalance agreements are managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken by the purchaser.

CNX Gas sells gas to accommodate the delivery points of its customers. In general this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty which qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are therefore reflected net on the income statement in Cost of Goods Sold and Other Operating Charges.

CNX Gas also provides gathering services to third parties by purchasing gas produced by the third party, at market prices less a fee. The gas purchased from third party producers is then resold by CNX Gas to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as purchased gas revenue and purchased gas costs in the Consolidated Statements of Income. Purchased gas revenue is recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CNX Gas from the third party producer.

Royalty Interest Gas Sales represent the revenues for the portion of production associated with royalty interest owners.

110

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Freight Revenue and Expenses:

Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight Revenue and Freight Expense, respectively.

Royalty Recognition:

Royalty expenses for coal rights are included in Cost of Goods Sold and Other Operating Charges when the related revenue for the coal sale is recognized. Royalty expenses for gas rights are included in Gas Royalty Interest Costs when the related revenue for the gas sale is recognized. These royalty expenses are paid in cash in accordance with the terms of each agreement. Revenues for coal and gas sold related to production under royalty contracts, versus owned by CONSOL Energy, are recorded on a gross basis. The recognized revenues for these transactions are not net of related royalty fees.

Contingencies:

CONSOL Energy, or our subsidiaries, from time to time 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. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense and are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.

Treasury Stock:

On September 12, 2008, CONSOL Energy’s Board of Directors announced a share repurchase program of up to $500,000 of the company’s common stock during a twenty-four month period beginning September 9, 2008, and ending September 8, 2010. Shares of common stock repurchased by us are recorded at cost as treasury stock and result in a reduction of stockholders’ equity in our Consolidated Balance Sheets. From time to time, treasury shares may be reissued as part of our stock-based compensation programs. When shares are reissued, we use the weighted average cost method for determining cost. The difference between the cost of the shares and the issuance price is added to or deducted from Capital in Excess of Par Value.

On December 21, 2005, CONSOL Energy’s Board of Directors announced a share repurchase program of up to $300,000 of the company’s common stock during a twenty-four month period beginning January 1, 2006 and ending December 31, 2007.

For the years ended December 31, 2008 and 2007, we had cash expenditures under our repurchase program of $97,794 and $80,157, respectively, funded primarily by cash generated from operations. The total common shares repurchased for the years ended December 31, 2008 and 2007 were 2,741,300 and 2,087,800 at an average cost of $35.59 and $38.14 per share, respectively. There were no cash expenditures under our repurchase program for the year ended December 31, 2009.

111

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Stock-Based Compensation:

Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of Stock Compensation Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the option vesting term. See Note 18 to the Audited Consolidated Financial Statements for a further discussion on stock-based compensation.

Earnings per Share:

Basic earnings per share are computed by dividing net earnings by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similar to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, and the assumed vesting of restricted and performance stock units if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised, and outstanding restricted and performance stock units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. In accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification, CONSOL Energy includes the impact of the proforma deferred tax assets in determining potential windfalls and shortfalls for purposes of calculating assumed proceeds under the treasury stock method. The table below sets forth the outstanding options, unvested restricted stock units, and unvested performance stock units that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive.


	For the Years Ended December 31,
	2009		2008		2007
Anti-Dilutive Options		695,743		370,987		133,343
Anti-Dilutive Restricted Stock Units		5,274		—		—
Anti-Dilutive Performance Stock Units		41,581		18,176		—

		742,598		389,163		133,343


	For the Years Ended December 31,
	2009		2008		2007
Net income attributable to CONSOL Energy Inc. shareholders	$	539,717	$	442,470	$	267,782

Average shares of common stock outstanding:
Basic		180,693,243		182,386,011		182,050,627
Effect of stock-based compensation awards		2,127,893		2,293,581		2,099,124

Dilutive		182,821,136		184,679,592		184,149,751

Earnings per share:
Basic	$	2.99	$	2.43	$	1.47

Dilutive	$	2.95	$	2.40	$	1.45

112

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Shares of common stock outstanding were as follows:


	2009	2008		2007
Balance, beginning of year	180,549,851	182,291,623		182,654,629
Issuance(1)	536,416	1,027,250		1,755,457
Repurchased-Treasury Stock Shares	—	(656,922	)	(2,118,463	)
Repurchased-Retired Shares	—	(2,112,100	)	—

Balance, end of year	181,086,267	180,549,851		182,291,623

(1)	See Note 18—Stock-based Compensation for additional information.

Accounting for Derivative Instruments:

CONSOL Energy accounts for derivative instruments in accordance with the Derivatives and Hedging Topic of the FASB Accounting Standards Codification. This requires CONSOL Energy to measure every derivative instrument (including certain derivative instruments embedded in other contracts) at fair value and record them in the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported, net of applicable taxes, in other comprehensive income. The ineffective portions of hedges are recognized in earnings in the current period.

CONSOL Energy formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in fair values or cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge, or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.

Accounting for Business Combinations:

The company accounts for its business acquisitions under the purchase method of accounting consistent with the requirements of the Business Combination Topic of the FASB Accounting Standards Codification. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.

Accounting for Carbon Emissions Offsets:

In 2008, CNX Gas, an 83.3% subsidiary, completed the independent verification and registration processes necessary to sell carbon emission offsets on the Chicago Climate Exchange. CNX Gas has verified approximately 8.4 million metric tons of offsets, CONSOL Energy has also verified approximately 8.3 million metric tons of offsets which may sell on the over-the-counter market. These offsets are recorded at their historical cost, which is zero. Sales of these emission offsets will be reflected in income as they occur. To date, no offsets have been sold.

Recently Adopted Accounting Guidance:

In December 2009, CONSOL adopted authoritative guidance issued by the FASB on extractive activities for oil and gas reserve estimation and disclosures. The objective of the new guidance is to align the oil and gas reserve estimation and disclosure requirements with the requirements of the Securities and Exchange

113

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Commission. The new guidance, among other purposes, is primarily intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves by expanding the definition of proved oil and gas producing activities, disclosing geographical areas that represent a certain percentage of proved reserves, updating the reserve estimation requirements for changes in practice and technology that have occurred over the past several decades and requiring that an entity continue to disclose separately the amounts and quantities for consolidated and equity method investments. CONSOL has applied this guidance to its Financial Statements for the year ended December 31, 2009.

Recent Accounting Guidance Not Yet Adopted:

Reclassifications:

Certain reclassifications of prior period data have been made to conform to the year ended December 31, 2009 as required by the Noncontrolling Interest Topic of the FASB Accounting Standards Codification.

Subsequent Events:

We have evaluated all subsequent events through February 9, 2010, the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.

Note 2—Acquisitions and Dispositions:

In August 2009, CONSOL Energy completed the lease assignment of CNX Gas’, an 83.3% owned subsidiary, previous headquarters. Total expense related to this transaction for the year ended December 31, 2009 was $1,500, which was recognized in the Cost of Goods Sold and Other Operating Charges.

In August 2009, CONSOL Energy completed a sale/lease-back of longwall shields for Bailey Mine. Cash proceeds from the sale were $16,011, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.

114

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

In July 2009, CNX Gas leased approximately 20,000 acres having Marcellus Shale potential from NiSource Energy Ventures, LLC, a subsidiary of the Columbia Energy Group, for a cash payment of $8,275 which is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statement of Cash Flows. The purchase price for the transaction was principally allocated to gas properties and related development.

In June 2009, CONSOL Energy recognized the fair value of the remaining lease payments in the amount of $10,499 in accordance with the Exit or Disposal Cost Obligations topic of the Financial Accounting Standards Board Accounting Standards Codification related to the Company’s previous headquarters. This liability has been recorded in Other Liabilities on the consolidated balance sheet at December 31, 2009. Total expense related to this transaction was $12,500, which was recognized in the Cost of Goods Sold and Other Operating Charges. This amount includes lease payments of $10,974 as well as the removal of a related asset of $1,526. Additionally, $5,832 was recognized in the Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the premises that occurred in 2005.

In February 2009, CONSOL Energy completed a sale/lease-back of longwall shields for Bailey Mine. Cash proceeds for the sale were $42,282, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.

In December 2008, CONSOL Energy completed the acquisition of the outstanding 51% interest in Southern West Virginia Energy, LLC (“SWVE”) for a cash payment of $11,521. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statement of Cash Flows. The purchase price was principally allocated to property, plant and equipment. SWVE wholly-owns Southern West Virginia Resources, LLC and Minway Contracting, LLC, and had previously been a 49% subsidiary of CONSOL Energy. Prior to the acquisition of the outstanding interest, SWVE had been fully consolidated in accordance with the Consolidation Topic of the Financial Accounting Standards Board Accounting Standards Codification by CONSOL Energy. The proforma results for this acquisition are not material to CONSOL Energy’s financial results.

In November 2008, CONSOL Energy completed the acquisition of North Penn Pipe & Supply, Inc. for a cash payment, net of cash acquired, of $22,550. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statements of Cash Flows. North Penn Pipe & Supply, Inc. is a distributor of oil and gas field equipment, primarily tubular goods, to the northern Appalachian Basin, a region stretching from the state of New York to southwestern Pennsylvania and northern West Virginia. The fair value of merchandise for resale acquired in this acquisition is $10,623 and is included in inventory on the Consolidated Balance Sheets as of the acquisition date. The pro forma results for this acquisition are not significant to CONSOL Energy’s financial results.

In October 2008 CONSOL Energy Inc.’s Board of Directors has authorized a purchase program for shares of CNX Gas Corporation common stock for an aggregate purchase price of up to $150 million. The authorization, which is not intended to take CNX Gas private, was effective as of October 21, 2008 for a twenty-four month period. During the year ended December 31, 2008, CONSOL Energy completed the purchase of $67,259 of CNX Gas stock on the open market at an average price of $26.53 per share. The purchase of these 2,531,400 shares changed CONSOL Energy’s ownership percentage in CNX Gas from 81.7% to 83.3% at December 31, 2008. During the year ended December 31, 2007, CONSOL Energy purchased $10,000 of CNX Gas stock on the open market at an average price of $26.87 per share. The purchase of these 372,000 shares changed CONSOL Energy’s ownership percentage in CNX Gas from 81.5% to 81.7% at December 31, 2007.

115

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

In July 2008, CNX Gas completed the acquisition of several leases and gas wells from KIS Oil & Gas Inc. for a cash payment of $19,324. The purchase price was principally allocated to property, plant and equipment. The sales agreement called for the transfer of 30 oil and gas wells and approximately 5,600 leased acres. This acquisition enhanced our acreage position in Northern Appalachia. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.

In June 2008, CNX Gas completed the acquisition of the remaining 50% interest in Knox Energy, LLC and Coalfield Pipeline Company not already owned by CNX Gas for a cash payment of $36,000 which was principally allocated to gas properties and related development and gas gathering equipment. Knox Energy, LLC had been proportionately consolidated into CONSOL Energy’s financial statements during 2008. During 2007 the equity method was used to account for these entities. Knox Energy, LLC is a natural gas production company and Coalfield Pipeline Company is a gathering and transportation company with operations in Tennessee. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.

In February 2008, CONSOL Energy completed the sale of the Mill Creek Mining Complex located in Kentucky. The sales agreement called for the transfer of all of the assets comprising the complex. Cash proceeds from the sale were $14,649, with our basis in the assets being $9,934. Accordingly, a gain of $4,715 was recorded on the transaction.

In December 2007, CONSOL Energy completed a sale/lease-back of 35 river barges. Cash proceeds from the sale were $16,895, with our basis in the equipment being $16,951. Accordingly, a loss of $56 was recorded on the transaction. The lease has been accounted for as an operating lease. The lease term is fourteen years.

In October 2007, CONSOL Energy acquired 100% of the outstanding shares in an oil and gas company for a cash payment of $12,385 which was principally allocated to gas properties and related development and gas gathering equipment. The acquired company is in the business of owning, operating and producing oil and gas wells and related pipelines. The acquired assets consisted of gas wells, equipment and connecting pipelines utilized in well operations. The acquisition was accounted for according to the Business Combination Topic of the Financial Accounting Standards Board Accounting Standards Codification. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.

In July, 2007, CONSOL Energy acquired 100% of the voting interest of AMVEST Corporation and certain subsidiaries and affiliates (AMVEST) for a cash payment, net of cash acquired, of $296,724 in a transaction accounted for according to the Business Combination Topic of the Financial Accounting Standards Board Accounting Standards Codification. The coal reserves acquired consisted of approximately 160 million tons of high quality, low sulfur steam and high-volatile metallurgical coal. Also included in the acquisition were four coal preparation plants, several fleets of modern mining equipment and a common short-line railroad that connects the coal preparation plants to the CSX and Norfolk and Southern rail interchanges. The results of operations of the acquired entities are included in CONSOL Energy’s Consolidated Statements of Income as of August 1, 2007.

The AMVEST acquisition, when combined with CONSOL Energy’s adjacent coal reserves, creates a large contiguous block of coal reserves in the Central Appalachian region. Also, included in the acquisition was a highly-skilled workforce proficient in Central Appalachian surface mining. This workforce combined with CONSOL Energy’s underground mining expertise will allow us to build and transfer knowledge among operations to focus the best skill sets to development requirements of the various parts of this reserve block.

116

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The unaudited pro forma results, assuming the acquisition had occurred at January 1, 2007 are estimated to be:


	For the Year Ended December 31, 2007
Revenue	$	3,902,186

Earnings Before Taxes	$	444,409

Net Income	$	279,074

Basic Earnings Per Share	$	1.53

Dilutive Earnings Per Share	$	1.52

The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of 2007, nor are they necessarily indicative of future consolidated results.

In July 2007, CONSOL Energy completed the acquisition of Piping & Equipment, Inc. for a cash payment, net of cash acquired, of $16,914. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statements of Cash Flows. Piping & Equipment, Inc. is a pipe, valve and fittings supplier with eight locations in Florida, Alabama, Louisiana and Texas. The fair value of merchandise for resale acquired in this acquisition is $8,481 and is included in inventory on the Consolidated Balance Sheets. The pro forma results for this acquisition are not significant to CONSOL Energy’s financial results.

In June 2007, CONSOL Energy exchanged certain coal assets in Northern Appalachia with Peabody Energy for coalbed methane and gas rights. This transaction was accounted for as a non-monetary exchange under the Fair Value Measurements and Disclosures Topic of the Financial Accounting Standards Board Accounting Standards Codification resulting in a pre-tax gain of $50,060. Also in June 2007, CONSOL Energy, through a subsidiary, acquired certain coalbed methane and gas rights from Peabody Energy for a cash payment of $15,000 plus approximately $1,650 of various other acquisition costs.

In June 2007, CONSOL Energy sold the rights to certain western Kentucky coal in the Illinois Basin to Alliance Resource Partners, L.P. for $53,309. This transaction resulted in a pre-tax gain of $49,868.

Note 3—Other Income:


	For the Years Ended December 31,
	2009		2008		2007
Royalty income	$	17,249	$	20,673	$	14,205
Equity in earnings of affiliates		15,707		11,140		6,551
Gain on disposition of assets		15,121		23,368		112,389
Contract settlements		12,450		—		—
Service income		11,796		14,298		12,623
Interest income		5,052		2,363		12,792
Charter & tramp towing income		4,838		11,164		2,601
Buchanan roof collapse insurance proceeds		—		50,000		10,000
Other		30,973		33,136		25,567

Total Other Income	$	113,186	$	166,142	$	196,728

117

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 4—Interest Expense:


	For the Years Ended December 31,
	2009			2008			2007
Interest on debt	$	39,524		$	45,627		$	40,766
Interest on other payables		3,766			2,718			4,648
Interest capitalized		(11,871	)		(12,162	)		(14,563	)

Total Interest Expense	$	31,419		$	36,183		$	30,851

Note 5—Taxes Other Than Income:


	For the Years Ended December 31,
	2009			2008			2007
Production taxes	$	183,307		$	188,581		$	163,346
Payroll taxes		48,702			49,829			43,828
Property taxes		47,934			44,107			41,586
Capital stock & franchise tax		8,895			6,568			7,475
Virginia employment enhancement tax credit		(3,715	)		(4,190	)		(3,159	)
Other		4,818			5,095			5,850

Total Taxes Other Than Income	$	289,941		$	289,990		$	258,926

Note 6—Income Taxes:

Income taxes (benefits) provided on earnings consisted of:


	For the Years Ended December 31,
	2009			2008		2007
Current:
U.S. Federal	$	134,231		$	87,658	$	62,704
U.S. State		41,482			14,549		11,284
Non-U.S.		(1,940	)		2,133		2,594

		173,773			104,340		76,582
Deferred:
U.S. Federal		49,672			101,869		40,278
U.S. State		(2,242	)		33,725		19,277

		47,430			135,594		59,555

Total Income Taxes	$	221,203		$	239,934	$	136,137

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The components of the net deferred tax assets are as follows:


	December 31,
	2009			2008
Deferred Tax Assets:
Postretirement benefits other than pensions	$	1,084,523		$	990,336
Mine closing		134,362			133,591
Alternative minimum tax		102,029			168,276
Pneumoconiosis benefits		81,724			75,124
Workers’ compensation		69,562			59,687
Salary retirement		68,820			74,967
Net operating loss		53,133			57,370
Capital lease		31,301			32,212
Reclamation		11,946			14,581
Other		120,911			78,923

Total Deferred Tax Assets		1,758,311			1,685,067
Valuation Allowance**		(61,623	)		(60,898	)

Net Deferred Tax Assets		1,696,688			1,624,169
Deferred Tax Liabilities:
Property, plant and equipment		(1,103,585	)		(1,085,054	)
Gas hedge		(46,129	)		(81,061	)
Advance mining royalties		(25,568	)		(23,445	)
Other		(22,726	)		(40,467	)

Total Deferred Tax Liabilities		(1,198,008	)		(1,230,027	)

Net Deferred Tax Assets	$	498,680		$	394,142

**	Valuation allowances of ($3,051) and ($58,572) have been allocated between current and long-term deferred tax assets respectively for 2009. Valuation allowances of ($2,663) and ($58,235) have been allocated between current and long-term deferred tax assets respectively for 2008.

A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. For the years ended December 31, 2009 and 2008, positive evidence considered included future income projections based on existing fixed price contracts and forecasted expenses, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence included financial and tax losses generated in prior periods and the inability to achieve forecasted results for those periods.

In 2007, CONSOL Energy implemented a prudent and feasible tax strategy that ensured the realization of Pennsylvania loss carry forward tax benefits. For 2009 and 2008, CONSOL Energy continues to report a deferred tax asset of $16,081 and $22,656 on an after federal tax adjusted basis relating to the remainder of its state operating loss carry forwards after valuation allowances, respectively. A review of the positive and negative evidence regarding these tax benefits, primarily the history of financial and tax losses on a separate company basis, concluded that the valuation allowances were warranted. A valuation allowance of $24,571 and $26,184 on an after federal tax adjusted basis has also been recorded for 2009 and 2008 respectively, against the deferred state tax asset attributable to future deductible temporary differences for certain CONSOL Energy subsidiaries with histories of financial and tax losses. The net operating loss carryforwards expire at various times between 2010 and 2027. Management will continue to assess the potential for realizing deferred tax assets based upon

119

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods as appropriate, that could materially impact net income. Included in the valuation allowance against the deferred state tax assets attributable to future deductible temporary differences for 2009 and 2008 are $7,952 and $8,496, respectively, of future tax benefits relating to other postretirement, pension and long-term disability benefits which are subject to a full valuation allowance. The decrease in the valuation allowances recognized related to other postretirement, pension and long-term disability benefits were recognized through Other Comprehensive Income in the applicable period.

We estimate that CONSOL Energy will utilize federal alternative minimum tax credits of $60,032 for the year ended December 31, 2009, thereby reducing the deferred tax asset associated with the prior years’ minimum tax credits. During 2009, the federal alternative minimum tax credits were increased $3,631 as a result of the 2008 accrual to 2008 return adjustments. As a result of the conclusion of the Internal Revenue Service (IRS) examination of the 2004 and 2005 tax returns, CONSOL Energy was able to utilize an additional $9,846 of alternative minimum tax credits.

The following is a reconciliation stated as a percentage of pretax income, of the United States statutory federal income tax rate to CONSOL Energy’s effective tax rate:


	For the Years Ended December 31,
	2009					2008					2007
	Amount			Percent		Amount			Percent		Amount			Percent
Statutory U.S. federal income tax rate	$	275,921		35.0	%	$	253,958		35.0	%	$	150,135		35.0	%
Excess tax depletion		(68,787	)	(8.7	)		(48,859	)	(6.7	)		(43,502	)	(10.1	)
Effect of medicare prescription drug, improvement and modernization act of 2003		2,112		0.3			2,112		0.3			1,796		0.4
Effect of domestic production activities		(12,707	)	(1.6	)		(7,721	)	(1.1	)		(915	)	(0.2	)
Net effect of state tax		25,377		3.2			31,169		4.3			20,086		4.7
Effect of foreign tax		(343	)	—			2,133		0.3			787		0.2
Other		(370	)	(0.1	)		7,142		1.0			7,750		1.7

Income Tax Expense/Effective Rate	$	221,203		28.1	%	$	239,934		33.1	%	$	136,137		31.7	%

A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:


	For the Years Ended December 31,
	2009			2008
Balance at beginning of period	$	84,554		$	91,696
Increase in unrecognized tax benefits resulting from tax positions taken during current period		17,461			11,725
Increase (decrease) in unrecognized tax benefits resulting from tax positions taken during prior period		7,825			(18,867	)
Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations		(3,800	)		—
Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities		(27,229	)		—

Balance at end of period	$	78,811		$	84,554

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

If these unrecognized tax benefits were recognized, $15,502 and $14,657 respectively would affect CONSOL Energy’s effective income tax rate.

CONSOL Energy and its subsidiaries file income tax returns in the U.S. federal, various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for the years before 2005. During the year ended December 31, 2009, CONSOL Energy was advised by the Canadian Revenue Agency that its appeal of tax deficiencies paid as a result of the Agency’s audit of the Company’s Canadian tax returns filed for years 1997 through 2002 had been successfully resolved. The Company recorded a tax refund receivable of $4,560 as a result of the audit settlement.

During the year ended December 31, 2009, CONSOL Energy paid federal and state income tax deficiencies of $12,798 and $608, respectively. The federal and state deficiencies paid, as a result of the 2004 and 2005 tax returns, had an insignificant impact on net income due to the tax deficiencies being the result of changes in the timing of certain tax deductions.

The IRS is commencing its audit of CONSOL Energy’s income tax returns filed for 2006 and 2007. The Company expects to conclude this examination and remit payment of any resulting tax deficiencies to federal and state taxing authorities before December 31, 2010. Since the IRS examination is in its initial stages, any resulting tax deficiency or overpayment cannot be estimated at this time. During the next year the statute of limitations for assessing additional income tax deficiencies will expire for certain tax years in several state tax jurisdictions. The expiration of the statute of limitations for these years will have an insignificant impact on CONSOL Energy’s total uncertain income tax positions and net income for the twelve-month period.

CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. At December 31, 2009 and 2008, the Company had an accrued liability of $8,338 and $10,518, respectively, for interest related to uncertain tax positions. The accrued interest liabilities include $2,409, $2,012 and $3,426 that were recorded in the Company’s Consolidated Statements of Income for the years ended December 31, 2009 and 2008, respectively. During the year ended December 31, 2009, CONSOL Energy paid interest of $4,590 related to income tax deficiencies to the IRS as a result of its examinations of the Company’s tax returns filed for the years 2002 through 2005.

CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2009 and 2008, there were no accrued penalties recognized.

Note 7—Mine Closing, Reclamation & Gas Well Closing:

CONSOL Energy accrues for reclamation, mine closing costs, perpetual water care costs and dismantling and removing costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes capitalized asset retirement costs by increasing the carrying amount of related long-lived assets, net of the associated accumulated depreciation. The obligation for asset retirements is included in Mine Closing, Reclamation, Gas Well Closing and Other Accrued Liabilities on the Consolidated Balance Sheets.

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The reconciliation of changes in the asset retirement obligations at December 31, 2009 and 2008 is as follows:


	As of December 31,
	2009			2008
Balance at beginning of period	$	544,314		$	530,897
Accretion expense		39,610			34,888
Payments		(31,458	)		(32,085	)
Revisions in estimated cash flows		(19,006	)		30,409
Other		(283	)		(19,795	)

Balance at end of period	$	533,177		$	544,314

For the year ended December 31, 2009, Other includes ($283) of various other items, none of which are individually significant. For the year ended December 31, 2008, Other includes ($19,618) for asset dispositions and ($177) of various other items, none of which are individually significant.

Note 8—Inventories:

Inventory components consist of the following:


	December 31,
	2009		2008
Coal	$	173,719	$	93,875
Merchandise for resale		44,842		43,074
Supplies		89,036		90,861

Total Inventories	$	307,597	$	227,810

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $13,696 and $14,716 at December 31, 2009 and 2008, respectively.

Note 9—Accounts Receivable Securitization:

CONSOL Energy and certain of our U.S subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. This facility allows CONSOL Energy to receive up to $165,000 on a revolving basis. The facility also allows for the issuance of letters of credit against the $165,000 capacity. At December 31, 2009, there were no letters of credit outstanding against the facility.

CONSOL Energy formed CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary for the sole purpose of buying and selling eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocable and without recourse, sell all of their eligible trade accounts receivable to financial institutions and their affiliates, while maintaining a subordinated interest in a portion of the pool of trade receivables. This retained interest, which is included in Accounts and Notes Receivable Trade in the Consolidated Balance Sheets, is recorded at fair value. Due to the short average collection cycle for the receivables that are part of this program, the fair value

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

of our retained interest approximates the total amount of the designated pool of accounts receivable reduced by the amount of accounts receivables sold to the third-party financial institutions under the program. CONSOL Energy will continue to service the trade receivables for the financial institutions for a fee based upon market rates for similar services.

The cost of funds under this facility is based upon commercial paper rates, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $2,990 and $5,814 for the year ended December 31, 2009 and 2008, respectively. These costs have been recorded as financing fees, which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in April 2012 with the underlying liquidity agreement renewing annually each April.

At December 31, 2009 and 2008, eligible accounts receivable totaled approximately $151,000 and $165,000, respectively. The subordinated retained interest approximated $101,000 at December 31, 2009. There was no subordinated retained interest at December 31, 2008. Accounts receivable totaling $50,000 and $165,000 were removed from the Consolidated Balance Sheets at December 31, 2009 and 2008, respectively. In accordance with the facility agreement, the company is able to receive proceeds based upon total eligible accounts receivable at the previous month end. CONSOL Energy’s $115,000 decrease and $39,600 increase in the accounts receivable securitization program for the years ended December 31, 2009 and 2008, respectively, is reflected in cash flows from operating activities in the Consolidated Statements of Cash Flows.

Note 10—Property, Plant and Equipment


	December 31,
	2009		2008
Coal and other plant and equipment	$	4,874,880	$	4,533,793
Coal properties and surface lands		1,284,795		1,264,920
Gas properties and related development		1,649,476		1,427,588
Gas gathering equipment		804,212		740,396
Airshafts		622,068		615,512
Leased coal lands		504,475		502,521
Mine development		573,037		527,991
Coal advance mining royalties		366,312		365,380
Gas advance royalties		2,700		2,187

Total Property, Plant and Equipment		10,681,955		9,980,288
Less—Accumulated depreciation, depletion and amortization		4,557,665		4,214,316

Net Property, Plant and Equipment	$	6,124,290	$	5,765,972

Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary greatly; however, the lease terms generally are extended automatically to the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction, and are legally considered real property interests. We also make advance payments (advanced mining royalties) to lessors under certain lease agreements that are recoupable against future production, and we make payments that are generally based upon a specified rate per ton or a percentage of gross realization from the sale of the coal. We evaluate our properties periodically for impairment issues or whenever events or circumstances indicate that the carrying amount may not be recoverable.

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Coal reserves are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned or accessible to the mine. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is placed into production. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material income effect from changes in estimates is disclosed in the period the change occurs.

Amortization of capitalized mine development costs associated with a coal reserve is computed on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material income effect from changes in estimates is disclosed in the period the change occurs. Amortization of development costs begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.

Amortization of wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised whenever there is an indication of the need for a revision, but at least once a year, and accounted for prospectively.

The following assets are amortized using the units-of-production method. Amounts reflect properties where mining or drilling operations have not yet commenced and therefore are not yet being amortized for the years ended December 31, 2009 and 2008, respectively.


	December 31,
	2009		2008
Coal properties and surface lands	$	393,368	$	395,880
Gas properties and related development		271,125		220,848
Airshafts		63,673		70,017
Leased coal lands		254,081		260,699
Mine development		114,800		98,842
Coal advance mining royalties		12,494		31,725
Gas advance royalties		2,405		2,187

Total	$	1,111,946	$	1,080,198

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CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

As of December 31, 2009 and 2008, plant and equipment includes gross assets under capital lease of $81,770 and $112,890, respectively. As of December 31, 2008, the Northern Appalachian coal segment maintained a $37,018 capital lease for longwall shields at Enlow Fork, which was included in Coal and other plant and equipment. In addition, for the years ended December 31, 2009 and 2008, the Gas segment maintains a capital lease for the Jewell Ridge Pipeline of $66,919, which is included in Gas gathering equipment. For the years ended December 31, 2009 and 2008, the Gas segment also maintains a capital lease for vehicles of $2,788 and $3,071, respectively, which are included in Gas properties and related development. For the years ended December 31, 2009 and 2008, the All Other segment maintains a capital lease for vehicles of $12,063 and $5,882, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was $21,893 and $31,929 at December 31, 2009 and 2008, respectively. Amortization expense for capital leases is included in depreciation expense. See Note 14—Leases for additional capital lease details.

Note 11—Short-Term Notes Payable:

CONSOL Energy has a five-year $1,000,000 senior secured credit facility, which extends through June 2012. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in 2012. The Agreement does provide for the release of collateral at the request of CONSOL Energy upon achievement of certain credit ratings. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 4.50 to 1.00, measured quarterly. The interest coverage ratio was 24.78 to 1.00 at December 31, 2009. The facility also includes a maximum leverage ratio covenant of not more than 3.25 to 1.00, measured quarterly. The leverage ratio was 0.87 to 1.00 at December 31, 2009. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends and merge with another corporation. At December 31, 2009, the $1,000,000 facility had $415,000 of borrowings outstanding and $268,360 of letters of credit outstanding, leaving $316,640 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 0.86% and 1.71% as of December 31, 2009 and 2008, respectively.

CNX Gas has a five-year $200,000 unsecured credit agreement which extends through October 2010. The agreement contains a negative pledge provision, whereas CNX Gas assets cannot be used to secure other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, purchase or redeem CNX Gas stock, pay dividends and merge with another corporation. The facility includes a maximum leverage ratio covenant of not more than 3.00 to 1.00, measured quarterly. The leverage ratio was 0.38 to 1.00 at December 31, 2009. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 68.17 to 1.00 at December 31, 2009. At December 31, 2009, the CNX Gas credit agreement had $57,850 of borrowings outstanding and $14,913 of letters of credit outstanding, leaving $127,237 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 1.69% and 2.01% as of December 31, 2009 and 2008, respectively.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 12—Other Accrued Liabilities:


	December 31,
	2009		2008
Subsidence liability	$	72,390	$	54,013
Accrued payroll and benefits		50,696		59,765
Accrued other taxes		42,559		41,916
Uncertain income tax positions		42,423		28,903
Short-term incentive compensation		35,710		29,329
Royalties		24,098		33,857
Other		112,095		78,925
Current portion of long-term liabilities:
Postretirement benefits other than pensions		164,747		145,429
Workers’ compensation		27,885		32,778
Mine closing		19,568		16,833
Pneumoconiosis benefits		9,676		9,833
Reclamation		3,192		4,108
Long term disability		5,468		5,389
Salary retirement		2,331		2,034
Deferred revenue		—		3,330

Total Other Accrued Liabilities	$	612,838	$	546,442

Note 13—Long-Term Debt:


	December 31,
	2009		2008
Debt:
Secured notes due March 2012 at 7.875% (par value of $250,000 less unamortized discount of $447 at December 31, 2009)	$	249,553	$	249,346
Baltimore Port Facility revenue bonds in series due December 2010 at 6.50%		30,865		30,865
Baltimore Port Facility revenue bonds in series due October 2011 at 6.50%		72,000		72,000
Advance royalty commitments		35,547		30,019
Notes due through 2011 at 6.10%		14,628		18,936
Other long-term notes maturing at various dates through 2031 (total value of $164 less unamortized discount of $4 at December 31, 2009)		160		1,121

		402,753		402,287
Less amounts due in one year		39,024		8,975

Total Long-Term Debt	$	363,729	$	393,312

Advance royalty commitments and the other long-term variable rate notes had a weighted average interest rate of approximately 7.36% at December 31, 2009 and 10.65% at December 31, 2008. The bonds and notes are carried net of debt discount, which is being amortized over the life of the issue.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Annual undiscounted maturities on long-term debt during the next five years are as follows:


Year Ended December 31,	Amount
2010	$	39,024
2011		85,344
2012		253,057
2013		2,847
2014		2,574
Thereafter		20,358

Total Long-Term Debt Maturities	$	403,204

Note 14—Leases:

CONSOL Energy uses various leased facilities and equipment in our operations. Future minimum lease payments under capital and operating leases, together with the present value of the net minimum capital lease payments, at December 31, 2009, are as follows:


Year Ended December 31, 2009	Capital Leases		Operating Leases
2010	$	10,997	$	79,649
2011		9,977		73,012
2012		8,641		54,562
2013		7,718		51,044
2014		7,469		41,900
Thereafter		50,379		166,358

Total minimum lease payments	$	95,181	$	466,525

Less amount representing interest (0.63% - 7.36%)		29,632

Present value of minimum lease payments		65,549
Less amount due in one year		6,370

Total Long-Term Capital Lease Obligation	$	59,179

Rental expense under operating leases was $77,960, $63,170 and $47,765 for the years ended December 31, 2009, 2008 and 2007, respectively.

Note 15—Pension and Other Postretirement Benefit Plans:

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer plans. The benefits for these plans are based primarily on years of service and employee’s pay near retirement.

The CONSOL Energy salaried plan allows for lump-sum distributions of benefits earned up until December 31, 2005 at the employees’ election. As of January 1, 2006, lump sum benefits have been frozen and prospectively the lump sum option has been eliminated. According to the Defined Benefit Plans Topic of the FASB Accounting Standards Codification, if the lump sum distributions made for the plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the service cost and interest cost for the plan

127

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

year, settlement accounting is required. Lump sum payments did not exceed the threshold during 2009 or 2008. Lump sum payments exceeded this threshold during 2007. Accordingly, CONSOL Energy recognized expense of $2,734 for the year ended December 31, 2007 in the results of operations. The adjustment equaled the unrecognized actuarial loss resulting from each individual who received a lump sum in that year. CONSOL Energy regularly monitors this situation.

During the year ended December 31, 2009, certain former and existing CNX Gas employees became eligible to participate in the CONSOL Energy Supplemental Retirement Plan. The additional benefit liabilities for these employees have been reflected as Plan Amendments in the reconciliation of the changes in benefit obligation for the year ended December 31, 2009.

Effective January 1, 2007, employees hired by CNX Gas, an 83.3% owned subsidiary, will not be eligible to participate in CNX Gas’ non-contributory defined benefit retirement plan. In lieu of participation in the non-contributory defined benefit retirement plan, these employees began receiving an additional 3% company contribution into their defined contribution plan.

Certain subsidiaries of CONSOL Energy provide medical and life insurance benefits to retired employees not covered by the Coal Industry Retiree Health Benefit Act of 1992. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare. Prior to August 1, 2003, substantially all employees became eligible for these benefits if they had ten years of company service and attained age 55. Effective August 1, 2003, the base eligibility was changed to age 55 with 20 years of service for salaried employees. In addition, effective January 1, 2004, a medical plan cost sharing arrangement with all salaried employees and retirees was adopted. These participants will now contribute a target of 20% of the medical plan operating costs. Contributions may be higher, dependent on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared by CONSOL Energy and the participants. Annual cost increases in excess of 6% will be the sole responsibility of the participants. Also, any salaried or non-represented hourly employees that were hired or rehired effective January 1, 2007, or later, will not become eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of two thousand two hundred and fifty dollars for each year of service at retirement. Newly employed inexperienced employees represented by the United Mine Workers of America, hired after January 1, 2007, will not be eligible to receive retiree benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked.

CONSOL Energy adopted the measurement provisions of the Defined Benefit Plans Topic of the FASB Accounting Standards Codification during the year ended December 31, 2008. As a result of the adoption, the Company recognized an increase of $2,278 and $42,599 in the liabilities for pension and other postretirement benefits, respectively. These increases were accounted for as a reduction in the January 1, 2008 balance of retained earnings.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2009 and 2008, is as follows:


	Pension Benefits at December 31,						Other Benefits at December 31,
	2009			2008			2009			2008
Change in benefit obligation:
Benefit obligation at beginning of period	$	571,772		$	523,381		$	2,638,773		$	2,484,829
Contractual liability(a)		—			103			—			2,486
Service cost (9/30/07-12/31/07)		—			2,438			—			2,639
Service cost		12,332			9,752			12,654			10,554
Interest cost (9/30/07-12/31/07)		—			8,257			—			39,960
Interest cost		35,483			33,029			151,451			159,837
Actuarial loss		78,529			54,243			197,066			95,372
Plan amendments		3,371			49			—			22,456
Participant contributions (9/30/07-12/31/07)		—			—			—			1,221
Participant contributions		—			—			4,633			4,884
Benefits paid (9/30/07-12/31/07)		—			(12,536	)		—			(37,545	)
Benefits paid		(47,465	)		(46,944	)		(160,484	)		(147,920	)

Benefit obligation at end of period	$	654,022		$	571,772		$	2,844,093		$	2,638,773

Change in plan assets:
Fair value of plan assets at beginning of period	$	375,261		$	453,203		$	—		$	—
Actual return on plan assets		66,537			(60,256	)		—			—
Company contributions (9/30/07-12/31/07)		—			905			—			36,323
Company contributions		67,667			42,080			155,851			143,036
Participant contributions(9/30/07-12/31/07)		—			—			—			1,221
Participant contributions		—			—			4,633			4,884
Benefits and other payments (9/30/07-12/31/07)		—			(12,536	)		—			(37,544	)
Benefits and other payments		(47,465	)		(48,135	)		(160,484	)		(147,920	)

Fair value of plan assets at end of period	$	462,000		$	375,261		$	—		$	—

Funded status:
Noncurrent assets	$	6		$	90		$	—		$	—
Current liabilities		(2,331	)		(2,034	)		(164,747	)		(145,429	)
Noncurrent liabilities		(189,697	)		(194,567	)		(2,679,346	)		(2,493,344	)

Net obligation recognized	$	(192,022	)	$	(196,511	)	$	(2,844,093	)	$	(2,638,773	)

Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial loss	$	362,901		$	336,541		$	1,152,630		$	1,005,922
Prior service credit		(3,141	)		(7,621	)		(168,561	)		(214,976	)

Net amount recognized (before tax effect)	$	359,760		$	328,920		$	984,069		$	790,946

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The components of net periodic benefit costs are as follows:


	Pension Benefits									Other Benefits
	For the Years Ended December 31,									For the Years Ended December 31,
	2009			2008			2007			2009			2008			2007
Components of net periodic benefit cost:
Service cost	$	12,332		$	9,752		$	11,015		$	12,654		$	10,555		$	10,988
Interest cost		35,483			33,029			28,710			151,451			159,837			139,221
Expected return on plan assets		(36,631	)		(33,671	)		(30,656	)		—			—			—
Settlement		—			—			2,734			—			—			—
Amortization of prior service cost (credit)		(1,109	)		(1,114	)		(1,114	)		(46,415	)		(48,625	)		(51,001	)
Recognized net actuarial loss		22,263			16,728			12,487			50,357			61,503			61,230

Benefit cost	$	32,338		$	24,724		$	23,176		$	168,047		$	183,270		$	160,438

Amounts included in accumulated other comprehensive income, expected to be recognized in 2010 net periodic benefit costs:


	Pension Benefits			Postretirement Benefits
Prior service cost (benefit) recognition	$	(735	)	$	(46,415	)
Actuarial loss recognition	$	31,460		$	69,593

The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan assets:


	As of December 31,
	2009		2008
Projected benefit obligation	$	653,925	$	571,155
Accumulated benefit obligation	$	580,498	$	511,275
Fair value of plan assets	$	462,000	$	374,657

Assumptions:

The weighted-average assumptions used to determine benefit obligations are as follows:


	Pension Benefits For the Year Ended December 31,				Other Benefits For the Year Ended December 31,
	2009		2008		2009		2008
Discount rate	5.79	%	6.28	%	5.87	%	6.20	%
Rate of compensation increase	4.09	%	4.05	%	—		—

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The weighted-average assumptions used to determine net periodic benefit costs are as follows:


	Pension Benefits at December 31,						Other Benefits at December 31,
	2009		2008		2007		2009		2008		2007
Discount rate	6.28	%	6.57	%	6.00	%	6.20	%	6.63	%	6.00	%
Expected long-term return on plan assets	8.00	%	8.00	%	8.00	%	—		—		—
Rate of compensation increase	4.05	%	4.01	%	3.65	%	—		—		—

The long-term rate of return is the sum of the portion of total assets in each asset class held multiplied by the expected return for that class, adjusted for expected expenses to be paid from the assets. The expected return for each class is determined using the plan asset allocation at the measurement date and a distribution of compound average returns over a 20-year time horizon. The model uses asset class returns, variances and correlation assumptions to produce the expected return for each portfolio. The return assumptions used forward-looking gross returns influenced by the current Treasury yield curve. These returns recognize current bond yields, corporate bond spreads and equity risk premiums based on current market conditions.

The assumed health care cost trend rates are as follows:


	At December 31,
	2009		2008		2007
Health care cost trend rate for next year	8.74	%	9.60	%	8.00	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	4.50	%	5.00	%	5.00	%
Year that the rate reaches ultimate trend rate	2023		2015		2013

Assumed health care cost trend rates have a significant effect on the amounts reported for the medical plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:


	1-Percentage Point Increase		1-Percentage Point Decrease
Effect on total of service and interest costs components	$	19,901	$	(17,043	)
Effect on accumulated postretirement benefit obligation	$	318,777	$	(276,481	)

Assumed discount rates also have a significant effect on the amounts reported for both pension and other benefit costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:


	0.25 Percentage Point Increase			0.25 Percentage Point Decrease
Pension benefit costs (decrease) increase	$	(750	)	$	740
Other postemployment benefits costs (decrease) increase	$	(3,833	)	$	3,779

Plan Assets:

The company’s overall investment strategy for its pension plan assets is to meet current and future benefit payment needs through diversification across asset classes, fund strategies and fund managers to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation. The target allocations for plan assets are 36 percent U.S. equity securities, 24 percent non-U.S. equity securities

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

and 40 percent fixed income. Both the equity and fixed income portfolios are comprised of both active and passive investment strategies. The Trust is primarily invested in Mercer Global Investments (MGI) Common Collective Trusts. Equity securities consist of investments in large and mid/small cap companies with non-U.S. equities being derived from both developed and emerging markets. Fixed income securities consist of U.S. as well as international instruments, including emerging markets. The core domestic fixed income portfolios invest in government, corporate, asset-backed securities and mortgage-backed obligations. The average quality of the fixed income portfolio must be rated at least “investment grade” by nationally recognized rating agencies. Within the fixed income asset class, investments are invested primarily across various strategies such that its overall profile strongly correlates with the interest rate sensitivity of the Trust’s liabilities in order to reduce the volatility resulting from the risk of changes in interest rates and the impact of such changes on the Trust’s overall financial status. Derivatives, interest rate swaps, options and futures are permitted investments for the purpose of reducing risk and to extend the duration of the overall fixed income portfolio; however, they may not be used for speculative purposes. All or a portion of the assets may be invested in mutual funds or other comingled vehicles so long as the pooled investment funds have an adequate asset base relative to their asset class; are invested in a diversified manner; and have management and/or oversight by an Investment Advisor registered with the Securities and Exchange Commission. The Retirement Board, as appointed by the CONSOL Energy Board of Directors, reviews the investment program on an ongoing basis including asset performance, current trends and developments in capital markets, changes in Trust liabilities and ongoing appropriateness of the overall investment policy.

The fair values of plan assets at December 31, 2009 by asset category are as follows:


	Fair Value Measurements at December 31, 2009
Asset Category	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash	$	231	$	231	$	—	$	—
US Equities(a)		3		3		—		—
MGI Collective Trusts
US Large Cap Growth Equity(b)		42,186		—		42,186		—
US Large Cap Value Equity(c)		41,205		—		41,205		—
US Small/Mid Cap Growth Equity(d)		17,069		—		17,069		—
US Small/Mid Cap Value Equity(e)		16,826		—		16,826		—
US Core Fixed Income(f)		17,755		—		17,755		—
Non-US Core Equity(g)		110,747		—		110,747		—
US Long Duration Investment Grade Fixed Income(h)		41,261		—		41,261		—
US Long Duration Fixed Income(i)		58,466		—		58,466		—
US Large Cap Passive Equity(j)		52,255		—		52,255		—
US Passive Fixed Income(k)		12,999		—		12,999		—
US Long Duration Passive Fixed Income(l)		23,589		—		23,589		—
US Ultra Long Duration Fixed Income(m)		27,408		—		27,408		—

Total	$	462,000	$	234	$	461,766	$	—

(a)	This category includes investments in United States common stocks.

(b)

This category invests primarily in common stock of large cap companies in the U.S. with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Russell 1000 Growth Index.

(c)

This category invests primarily in U.S. large cap companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Russell 1000 Value Index.

(d)

This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.

(e)

This category invests in small to mid-sized U.S. companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.

(f)

This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest in opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targeted to be within 20% of the benchmark’s duration. Total exposure to high yield issues is typically less than 10%, inclusive of direct investment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.

(g)

This category invests in all cap companies operating in developed and emerging markets outside the U.S. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the MSCI EAFE Index.

(h)

This category invests in a passively managed U.S. long duration investment grade portfolio at a 90% weight and a passively managed U.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing for short term liquidity through a strategic allocation to U.S. Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% to the Barclays Capital Long Treasury.

(i)

This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 11 years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds, and TIPs. The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.

(j)	This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.

(k)	This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Aggregate Index.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

(l)	This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 11 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.

(m)

This category seeks to reduce the volatility of the plan’s funded status and extend the duration of the assets by investing in a series of ultra long duration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return in excess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets to the plan’s liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.

There are no direct investments in CONSOL Energy stock held by these plans at December 31, 2009 or 2008.

There are no assets in the other postretirement benefit plans at December 31, 2009 or 2008.

Cash Flows:

CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Currently, depending on asset values and asset returns held in the trust, we expect to contribute $63,600 to our pension plan trust in 2010. Pension benefit payments are primarily funded from the trust. CONSOL Energy does not expect to contribute to the other postemployment plan in 2010. We intend to pay benefit claims as they are due.

The following benefit payments, reflecting expected future service, are expected to be paid:


	Pension Benefits		Other Benefits
2010	$	38,212	$	164,747
2011	$	36,358	$	175,356
2012	$	44,017	$	182,548
2013	$	44,445	$	189,550
2014	$	47,684	$	196,119
Year 2015-2019	$	269,407	$	1,040,248

Note 16—Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation:

CONSOL Energy is also responsible to compensate individuals who sustain employment related physical injuries or some types of occupational diseases and, on some occasions, for costs of their rehabilitation. Workers’

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

compensation laws will also compensate survivors of workers who suffer employment related deaths. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy primarily provides for these claims through a self-insurance program. CONSOL Energy recognizes an actuarial present value of the estimated workers’ compensation obligation calculated by independent actuaries. The calculation is based on claims filed and an estimate of claims incurred but not yet reported as well as various assumptions. The assumptions include discount rate, future health care trend rate, benefit duration and recurrence of injuries. Actuarial gains associated with workers’ compensation have resulted from discount rate changes, several years of favorable claims experience, various favorable state legislation changes and overall lower incident rates than our assumptions.

CONSOL Energy adopted the measurement provisions of the Defined Benefit Plans Topic of the FASB Accounting Standards Codification during the year ended December 31, 2008. As a result of this adoption, the Company recognized an increase of $4,871 and $11,523 in liabilities for coal workers’ pneumoconiosis and workers’ compensation, respectively. These increases were accounted for as a reduction in the January 1, 2008 balance of retained earnings.


	CWP December 31,						Workers’ Compensation December 31,
	2009			2008			2009			2008
Change in benefit obligation:
Benefit obligation at beginning of period	$	200,094		$	182,872		$	159,761		$	162,060
Contractual liability(a)		—			1,689			—			355
State administrative fees and insurance bond premiums		—			—			6,710			5,509
Service cost (9/30-12/31)		—			1,934			—			7,257
Service cost		9,774			7,736			31,795			29,030
Interest cost (9/30-12/31)		—			2,937			—			2,082
Interest cost		12,054			11,748			8,765			8,328
Actuarial (gain) loss		(16,584	)		4,117			9,825			(4,236	)
Benefits paid (9/30-12/31)		—			(1,455	)		—			(11,834	)
Benefits paid		(10,697	)		(11,484	)		(37,588	)		(38,790	)

Benefit obligation at end of period	$	194,641		$	200,094		$	179,268		$	159,761

Current liabilities	$	(9,676	)	$	(9,833	)	$	(27,885	)	$	(32,778	)
Noncurrent liabilities		(184,965	)		(190,261	)		(151,383	)		(126,983	)

Net obligation recognized	$	(194,641	)	$	(200,094	)	$	(179,268	)	$	(159,761	)

Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial gain	$	(184,666	)	$	(187,672	)	$	(45,232	)	$	(59,257	)
Prior service credit		(1,851	)		(2,579	)		—			—

Net amount recognized (before tax effect)	$	(186,517	)	$	(190,251	)	$	(45,232	)	$	(59,257	)

(a)	Amounts offset by a contractual receivable included in Other Assets on the Consolidated Balance Sheets.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The components of the net periodic cost (credit) are as follows:


	CWP For the Years Ended December 31,									Workers’ Compensation For the Years Ended December 31,
	2009			2008			2007			2009			2008			2007
Components of Net Periodic Cost (Credit):
Service cost	$	7,074		$	5,036		$	5,856		$	28,394		$	29,030		$	29,659
Interest cost		12,054			11,748			11,401			8,765			8,328			8,356
Legal and administrative costs		2,700			2,700			2,700			3,401			3,224			3,259
Amortization of prior service cost		(728	)		(728	)		(728	)		—			—			—
Recognized net actuarial gain		(19,590	)		(23,383	)		(22,371	)		(4,200	)		(4,938	)		(3,953	)
State administrative fees and insurance bond premiums		—			—			—			6,710			5,509			10,591

Net periodic cost (credit)	$	1,510		$	(4,627	)	$	(3,142	)	$	43,070		$	41,153		$	47,912

Amounts included in accumulated other comprehensive income, expected to be recognized in 2010 net periodic benefit costs:


	CWP Benefits			Workers’ Compensation Benefits
Prior service benefit recognition	$	(728	)	$	—
Actuarial gain recognition	$	(19,196	)	$	(3,072	)

Assumptions:

The weighted-average discount rate used to determine benefit obligations and net periodic (benefit) cost are as follows:


	CWP For Years Ended December 31,						Workers’ Compensation For Years Ended December 31,
	2009		2008		2007		2009		2008		2007
Benefit obligations	5.84	%	6.23	%	6.62	%	5.55	%	5.90	%	5.94	%
Net Periodic (benefit) costs	6.23	%	6.62	%	6.00	%	5.90	%	5.94	%	6.00	%

Assumed discount rates have a significant effect on the amounts reported for both CWP benefits and Workers’ Compensation costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:


	0.25 Percentage Point Increase			0.25 Percentage Point Decrease
CWP benefit (decrease) increase	$	(655	)	$	643
Workers’ Compensation costs (decrease) increase	$	(29	)	$	23

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Cash Flows:

CONSOL Energy does not intend to make contributions to the CWP or Workers’ Compensation plans in 2010. We intend to pay benefit claims as they become due.

The following benefit payments, which reflect expected future claims as appropriate, are expected to be paid:


			Workers’ Compensation
	CWP Benefits		Total Benefits		Actuarial Benefits		Other Benefits
2010	$	9,676	$	34,359	$	27,885	$	6,474
2011	$	10,217	$	35,989	$	29,256	$	6,733
2012	$	10,791	$	37,365	$	30,363	$	7,002
2013	$	11,351	$	38,507	$	31,225	$	7,282
2014	$	11,885	$	39,437	$	31,863	$	7,574
Year 2015-2019	$	65,428	$	204,744	$	162,081	$	42,663

Note 17—Other Employee Benefit Plans:

UMWA Pension and Benefit Trusts:

Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan negotiated with the United Mine Workers of America (the UMWA) and contained in the National Bituminous Coal Wage Agreement (the NBCWA). The NBCWA currently calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The current contribution rates called for by the NBCWA are: $4.25 per hour worked in 2009, $5.00 per hour worked in 2010 and $5.50 per hour worked in 2011. Total contributions for a year may differ from total expenses for the year due to the timing of actual contributions compared to the date of assessment. Total contributions to the UMWA 1974 Pension Trust were $25,620, $21,140 and $11,354 for the years ended December 31, 2009, 2008 and 2007, respectively. These multi-employer pension plan contributions are expensed as incurred. The Pension Protection Act requires a minimum funding ratio of 80% be maintained for this multi-employer pension plan and if the plan is determined to have a funded ratio of less than 80% it will be deemed to be “endangered” or "seriously endangered", and if less than 65%, it will be deemed to be in “critical” status, and will in either case be subject to additional funding requirements. Under the Pension Act, the multi-employer plan's actuary must certify the plan's funded status for each plan year. Based on an estimated funded percentage of 91.4%, a certification was provided by the multi-employer plan actuary, stating that the 1974 Pension Trust was in neither “endangered” nor “critical” status for the plan year beginning July 1, 2008. However, the volatile economic environment and the recent rapid deterioration in the equity markets caused investment income and the value of investment assets held in the 1974 Pension Trust to decline and lose value.

In late 2008, the Worker, Retiree and Employer Recovery Act of 2008 (“WRERA”) was enacted. Under WRERA, a plan is permitted temporarily to avoid applying the Pension Act's requirements for improving its financial status by giving a plan the option to elect to retain its prior year zone status and to freeze the plan's zone status at the level determined for 2008. WRERA also required that the plan's actuary certify the plan's actual zone status for 2009. On September 28, 2009, based on an estimated funded percentage of 74%, the 1974 Pension Trust's actuary provided the Pension Act zone certification for 2009, certifying that the 1974 Pension Trust is “seriously endangered” for the plan year beginning July 1, 2009. Thereafter, pursuant to WRERA, the 1974 Pension Trust elected to retain its 2008 funded status of neither “endangered” nor “critical” for the plan year

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(Dollars in thousands, except per share data)

beginning July 1, 2009. If the freeze election had not been made, the 1974 Pension Trust's zone status for 2009 as certified by its actuary would have been “seriously endangered” and the 1974 Pension Trust would have been required to develop a funding improvement plan.

The freeze election only applies for the 2009 plan year. If the 1974 Pension Trust is certified to be endangered, seriously endangered or in critical status for the plan year beginning July 1, 2010, steps will have to be taken under the Pension Act to improve its funded status. Such a determination would require certain subsidiaries of CONSOL Energy to make additional contributions pursuant to a funding improvement plan implemented in accordance with the Pension Act and, therefore, could have a material impact on our operating results.

The Coal Industry Retiree Health Benefit Act of 1992 (the Act) created two multi-employer benefit plans: (1) the United Mine Workers of America Combined Benefit Fund (the Combined Fund) into which the former UMWA Benefit Trusts were merged, and (2) the 1992 Benefit Fund. CONSOL Energy subsidiaries account for required contributions to these multi-employer trusts as expense when incurred.

The Combined Fund provides medical and death benefits for all beneficiaries of the former UMWA Benefit Trusts who were actually receiving benefits as of July 20, 1992. The 1992 Benefit Fund provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and who actually retired between July 20, 1992 and September 30, 1994. The Act provides for the assignment of beneficiaries to former employers and the allocation of unassigned beneficiaries (referred to as orphans) to companies using a formula set forth in the Act. The Act requires that responsibility for funding the benefits to be paid to beneficiaries be assigned to their former signatory employers or related companies. This cost is recognized when contributions are assessed. Total contributions under the Act were $22,646, $24,343 and $32,916 for the years ended December 31, 2009, 2008 and 2007, respectively. Costs were reduced in 2007 by $30,389 due to the March 2007 settlement agreement with the Combined Fund that resolved all previous issues relating to the calculation of payments to the Combined Fund. See Note 24—Commitments and Contingencies in Notes to Audited Financial Statements for additional details on the settlement agreement. Based on available information at December 31, 2009, CONSOL Energy’s obligation for the Act is estimated at approximately $182,084.

The UMWA 1993 Benefit Plan is a defined contribution plan that was created as the result of negotiations for the NBCWA of 1993. This plan provides health care benefits to orphan UMWA retirees who are not eligible to participate in the Combined Fund, the 1992 Benefit Fund, or whose last employer signed the 1993 or a later NBCWA and who subsequently goes out of business. Contributions to the trust under the 2007 agreement are $1.44 per hour worked by UMWA represented employees for the year ended December 31, 2009, comprised of a $0.50 per hour worked under the labor agreement and $0.94 per hour worked by UMWA represented employees under the Tax Relief and Health Care Act of 2006 (the 2006 Act). Contributions to the trust under the 2007 agreement are $1.77 per hour worked by UMWA represented employees for the year ended December 31, 2008, comprised of a $0.50 per hour worked under the labor agreement and $1.27 per hour worked by UMWA represented employees under the 2006 Act. The contribution rate for the year ended December 31, 2007, was $2.00 per hour worked by UMWA represented employees, comprised of $0.50 per hour worked under the labor agreement and $1.50 per hour worked under the 2006 Act. Total contributions were $9,072, $11,494 and $11,627 for the years ended December 31, 2009, 2008 and 2007, respectively.

Pursuant to the provisions of the 2006 Act and the 1992 Plan, CONSOL Energy is required to provide security in an amount based on the annual cost of providing health care benefits for all individuals receiving benefits from the 1992 Plan who are attributable to CONSOL Energy, plus all individuals receiving benefits from

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(Dollars in thousands, except per share data)

an individual employer plan maintained by CONSOL Energy who are entitled to receive such benefits. In accordance with the 2006 Act and the 1992 Plan, the outstanding letters of credit to secure our obligation were $61,734 and $60,695 for years ended December 31, 2009 and 2008, respectively. The 2009 and 2008 security amounts were based on the annual cost of providing health care benefits and included a reduction in the number of eligible employees.

At December 31, 2009, approximately 34.5% of CONSOL Energy’s workforce was represented by the UMWA.

Equity Incentive Plans:

CONSOL Energy has an equity incentive plan that provides grants of stock-based awards to key employees and to non-employee directors. See Note 18 for a further discussion of CONSOL Energy’s stock-based compensation.

The CNX Gas equity incentive plan consists of the following components: stock options, stock appreciation rights, restricted stock units, performance awards, performance share units, cash awards and other stock-based awards. The total number of shares of CNX Gas common stock with respect to which awards may be granted under CNX Gas’ plan is 2,500,000. CNX Gas stock-based compensation expense, excluding allocated portions from CONSOL Energy resulted in pre-tax expense of $6,311, $3,379 and $3,260 to CONSOL Energy for the years ended December 31, 2009, 2008 and 2007, respectively.

Long Term Incentive Compensation:

CNX Gas had a long-term incentive program. This program allowed for the award of performance share units (PSUs). A PSU represents a contingent right to receive a cash payment, determined by reference to the value of one share of the Company’s common stock. The total number of units earned, if any, by a participant was based on the Company’s total stock holder return relative to the stock holder return of a pre-determined peer group of companies. CNX Gas recognized compensation costs over the requisite service period. The basis of the compensation costs was re-valued quarterly. Approximately $8,779 and $2,231 of compensation costs have been recognized for the years ended December 31, 2008 and 2007, respectively. A credit to expense of approximately $1,434 was recognized for the year ended December 31, 2009 as a result of the decline in the value of the expected payout prior to the exchange transaction discussed below.

During the second quarter of 2009, CNX Gas recognized the effect of an exchange offer that allowed participants in the CNX Gas Long-Term Incentive Program to exchange their unvested performance share units for CONSOL Energy restricted stock units. The excess fair value of the replacement restricted stock units over the original performance stock units resulted in $2,738 of incremental restricted stock compensation expense being immediately recognized. Additionally, a liability of $10,347 for the cash settlement of the CNX Gas performance share units was reclassified into equity due to the issuance of RSUs. As a result of the completed exchange offer there are no outstanding performance share units at December 31, 2009.

Investment Plan:

CONSOL Energy has an investment plan available to all domestic, non-represented employees. Effective January 1, 2006, the company match was 6% of base pay for all non-represented employees except for those employees of Fairmont Supply Company whose match remains at 50% of the first 12% of base pay. In addition,

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

effective January 1, 2007, the definition of eligible compensation for employee deferrals and company match was amended to include overtime for all non-represented employees except for those employees of Fairmont Supply Company whose definition of eligible compensation will remain unchanged. CNX Gas employees hired on or after January 1, 2007 also receive an additional 3% non-elective contribution in lieu of participation in the CNX Gas pension plan. Total payments and costs were $24,353, $23,091 and $17,896 for the years ended December 31, 2009, 2008 and 2007, respectively.

Long-Term Disability:

CONSOL Energy has a Long-Term Disability Plan available to all full-time salaried employees. The benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled.


	For The Years Ended December 31,
	2009			2008			2007
Benefit Costs	$	3,642		$	3,998		$	3,050
Discount rate assumption used to determine net periodic benefit oblications		5.92	%		5.92	%		5.99	%

Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities—Other and Other Accrued Liabilities and amounted to $30,097 and $29,645 for the years ended December 31, 2009 and 2008, respectively.

Note 18—Stock-Based Compensation:

CONSOL Energy adopted the CONSOL Energy Inc. Equity Incentive Plan on April 7, 1999. The plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments to the plan have been approved by the Board of Directors since the commencement of the plan. In 2009, the Board of Directors approved an increase in the total number of shares by 5,600,000 bringing the total number of shares of common stock that can be covered by grants at December 31, 2009 to 23,800,000 of which 2,600,000 are available for issuance of awards other than stock options. The Plan, as amended, will provide that the aggregate number of shares available for issuance under the Plan will be reduced by one share for each share issued in settlement of Performance Share Units (PSUs) or Restricted Stock Units (RSUs) and by 1.44 for any other award. No award of stock options may be exercised under the plan after the tenth anniversary of the effective date of the award.

In accordance with the Stock Compensation Topic of the FASB Accounting Standards Codification, CONSOL Energy recognizes stock-based compensation costs net of an estimated forfeiture rate and recognizes the compensation costs for only those shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the option vesting term, or to an employee’s eligible retirement date, if earlier and applicable. The total stock-based compensation expense recognized was $32,723, $21,807 and $20,983 for the years ended December 31, 2009, 2008 and 2007, respectively. The related deferred tax benefit totaled $12,490, $8,293 and $7,938, for the years ended December 31, 2009, 2008 and 2007, respectively.

CONSOL Energy examined its historical pattern of option exercises in an effort to determine if there were any discernable activity patterns based on certain employee populations. From this analysis, CONSOL Energy identified two distinct employee populations. CONSOL Energy used the Black-Scholes option pricing model to value the options for each of the employee populations. The table below presents the weighted average expected term in years of the two employee populations. The expected term computation is based upon historical exercise

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

patterns and post-vesting termination behavior of the populations. The risk-free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S. Treasury obligations for the expected term of the award. The expected forfeiture rate is based upon historical forfeiture activity. A combination of historical and implied volatility is used to determine expected volatility and future stock price trends. Total fair value of options granted during the years ended December 31, 2009, 2008 and 2007 were $9,950, $11,395 and $9,912, respectively. The fair value of share-based payment awards was estimated using the Black-Scholes option pricing model with the following assumptions and weighted average fair values:


	December 31,
	2009			2008			2007
Weighted average fair value of grants	$	14.48		$	29.44		$	11.93
Risk-free interest rate		1.45	%		2.59	%		4.70	%
Expected dividend yield		1.40	%		0.50	%		0.80	%
Expected forfeiture rate		2.00	%		2.00	%		2.00	%
Expected volatility		75.60	%		46.60	%		38.20	%
Expected term in years		4.10 years			3.97 years			4.07 years

A summary of the status of stock options granted is presented below:


	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Balance at December 31, 2008	4,894,864		$	26.40
Granted	687,117		$	27.89
Exercised	(167,424	)	$	15.55
Forfeited	(27,416	)	$	39.89

Balance at December 31, 2009	5,387,141		$	26.86	5.46	$	134,166

Vested and expected to vest	5,339,497		$	26.72	5.50	$	133,573

Exercisable at December 31, 2009	4,024,879		$	26.80	4.59	$	114,105

These stock options will terminate ten years after the date on which they were granted. The employee stock options, covered by the Equity Incentive Plan adopted April 7, 1999, vest 25% per year, beginning one year after the grant date for awards granted prior to 2007. Employee stock options awarded after December 31, 2006 vest 33% per year, beginning one year after the grant date. There are 4,848,213 stock options outstanding under the Equity Incentive plan. Additionally, there are 446,180 fully vested employee stock options outstanding which had vesting terms ranging from six months to one year. Non-employee director stock options vest 33% per year, beginning one year after the grant date. There are 92,747 stock options outstanding under these grants. The vesting of all options will accelerate in the event of death, disability or retirement and may accelerate upon a change in control of CONSOL Energy. In 2008, the compensation committee of the board of directors changed the retirement eligible acceleration of vesting to require a minimum vesting period of twelve months. This change is effective for all stock based compensation awards issued after January 1, 2008.

The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CONSOL Energy’s closing stock price on the last trading day of the year ended December 31, 2009, and

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

the option’s exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2009. This amount varies based on the fair market value of CONSOL Energy’s stock. Total intrinsic value of options exercised for the year ended December 31, 2009, 2008 and 2007 was $4,502, $55,131 and $65,294, respectively.

Cash received from option exercises for the years ended December 31, 2009, 2008 and 2007 was $2,547, $15,215 and $19,224, respectively. The excess tax benefit realized for the tax deduction from option exercises totaled $3,270, $22,003 and $23,682 for the years ended December 31, 2009, 2008 and 2007, respectively. This excess tax benefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.

Under the Equity Incentive Plan, CONSOL Energy granted certain employees and non-employee directors restricted stock unit awards. These awards entitle the holder to receive shares of common stock as the award vests. Compensation expense will be recognized over the vesting period of the units. The total fair value of the restricted stock units granted during the years ended December 31, 2009, 2008 and 2007 were $42,720, $5,950 and $6,373, respectively. The total fair value of shares vested during the years ended December 31, 2009, 2008 and 2007 was $18,092, $4,720 and $3,641, respectively. The following represents the unvested restricted stock units and corresponding fair value (based upon the closing share price) at the date of grant:


	Number of Shares		Weighted Average Grant Date Fair Value
Nonvested at December 31, 2008	389,296		$	42.57
Granted	1,489,538		$	28.68
Vested	(553,701	)	$	32.68
Forfeited	(30,756	)	$	28.85

Nonvested at December 31, 2009	1,294,377		$	31.15

Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance share unit awards. These awards entitle the holder to receive shares of common stock subject to the achievement of certain market and performance goals. Compensation expense will be recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. At December 31, 2009, achievement of the market and performance goals is believed to be probable. The total fair value of performance share units granted during the years ended December 31, 2009, 2008 and 2007 were $5,684, $4,904 and $3,237. The following represents the unvested performance share unit awards and their corresponding fair value (based upon the closing share price) at the date of grant:


	Number of Shares	Weighted Average Grant Date Fair Value
Nonvested at December 31, 2008	126,877	$	64.16
Granted	164,186	$	34.62

Nonvested at December 31, 2009	291,063	$	47.50

As of December 31, 2009, $24,570 of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.57 years. When employee stock options are exercised and restricted and performance share unit awards become vested, the issuances are made from CONSOL Energy’s treasury stock shares which have been acquired as part of CONSOL Energy’s share repurchase program as previously discussed in Note 1.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 19—Accumulated Other Comprehensive Loss:

Components of accumulated other comprehensive loss consists of the following:


	Treasury Rate Lock			Change in Fair Value of Cash Flow Hedges			Adjustments for Actuarially Determined Liabilities			Adjustments for Non- controlling Interest			Accumulated Other Comprehensive Loss
Balance at December 31, 2006	$	421		$	1,346		$	(377,484	)	$	—		$	(375,717	)
Net increase in value of cash flow hedges		—			23,943			—			(4,370	)		19,573
Reclassification of cash flow hedges from other comprehensive income to earnings		—			(19,729	)		—			3,601			(16,128	)
Current period change		(81	)		—			(47,009	)		78			(47,012	)

Balance at December 31, 2007		340			5,560			(424,493	)		(691	)		(419,284	)
Net increase in value of cash flow hedges		—			117,699			—			(20,646	)		97,053
Reclassification of cash flow hedges from other comprehensive income to earnings		—			947			—			(166	)		781
Current period change		(77	)		—			(140,305	)		19			(140,363	)
Prior period adjustment		—			—			(87	)		—			(87	)

Balance at December 31, 2008		263			124,206			(564,885	)		(21,484	)		(461,900	)
Net increase in value of cash flow hedges		—			186,824			—			(31,162	)		155,662
Reclassification of cash flow hedges from other comprehensive income to earnings		—			(239,956	)		—			40,024			(199,932	)
Current period change		(83	)		—			(134,549	)		298			(134,334	)

Balance at December 31, 2009	$	180		$	71,074		$	(699,434	)	$	(12,324	)	$	(640,504	)

The cash flow hedges that CONSOL Energy holds are disclosed in Note 23. The adjustments for Actuarially Determined Liabilities are disclosed in Note 15 and Note 16.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 20—Supplemental Cash Flow Information:


	For the Years Ended December 31,
	2009			2008			2007
Cash paid during the year for:
Interest (net of amounts capitalized)	$	26,425		$	33,236		$	26,415
Income taxes	$	131,043		$	95,101		$	103,194
Non-cash investing and financing activities:
Adoption of Accounting for Uncertainty in Income Taxes
Change in Assets	$	—		$	—		$	(39,207	)
Change in Liabilities	$	—		$	—		$	(39,207	)
Businesses acquired (Note 2)
Fair value of assets acquired	$	28,113		$	(26,892	)	$	(132,694	)
Liabilities assumed	$	28,113		$	(26,892	)	$	(132,694	)
Note received from property sales	$	(1,789	)	$	—		$	(200	)
Capital Lease Obligation
Change in Assets	$	(3,375	)	$	2,622		$	(1,083	)
Change in Liabilities	$	(3,375	)	$	2,622		$	(1,083	)
Purchase of Property, Plant and Equipment
Change in Assets	$	46,938		$	(75,818	)	$	3,219
Change in Liabilities	$	46,938		$	(75,818	)	$	3,219
Accounting for Mine Closing, Reclamation and Gas Well Closing Costs
Change in Assets	$	283		$	(29,088	)	$	3,403
Change in Liabilities	$	283		$	(29,088	)	$	3,403

Note 21—Concentration of Credit Risk and Major Customers:

CONSOL Energy markets steam coal, principally to electric utilities in the United States, Canada and Western Europe, metallurgical coal to steel and coke producers worldwide, and natural gas primarily to gas wholesalers. As of December 31, 2009 and 2008, accounts receivable from utilities were $215,743 and $222,808, respectively. As of December 31, 2009 and 2008, accounts receivable from steel and coke producers were $43,448 and $40,788, respectively. As of December 31, 2009 and 2008, accounts receivable from gas wholesalers were $43,421 and $61,764, respectively. Credit is extended based on an evaluation of the customer’s financial condition, and generally collateral is not required. Credit losses have been consistently minimal.

For the years ended December 31, 2009, 2008 and 2007, no customer comprised over 10% of our revenues.

Note 22—Fair Values of Financial Instruments:

Effective January 1, 2008, CONSOL Energy adopted the provision for Fair Value of Financial Assets and Financial Liabilities as required by the Financial Accounting Standards Board Accounting Standards Codification. As a result of the adoption, CONSOL Energy elected not to measure any additional financial assets or liabilities at fair value, other than those which were previously recorded at fair value prior to the adoption.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The financial instruments measured at fair value on a recurring basis are summarized below:


	Fair Value Measurements at December 31, 2009
Description	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges	$	—	$	117,483	$	—

The following methods and assumptions were used to estimate the fair values of financial instruments, which the fair value option was not elected:

Cash and cash equivalents: The carrying amount reported in the balance sheets for cash and cash equivalents approximates its fair value due to the short maturity of these instruments.

Short-term notes payable: The carrying amount reported in the balance sheets for short-term notes payable approximates its fair value due to the short-term maturity of these instruments.

Long-term debt: The fair values of long-term debt are estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows.

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:


	December 31, 2009						December 31, 2008
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	65,607		$	65,607		$	138,512		$	138,512
Short-term notes payable	$	(472,850	)	$	(472,850	)	$	(557,700	)	$	(557,700	)
Long-term debt	$	(402,753	)	$	(420,056	)	$	(402,287	)	$	(390,278	)

Note 23—Derivative Instruments:

CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. Our derivatives are accounted for under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification. We measure each derivative instrument at fair value and record it on the balance sheet as either an asset or liability. Changes in the fair value of the derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in Other Comprehensive Income or Loss (OCI) and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year. CONSOL Energy currently utilizes only cash flow hedges that are considered highly effective.

CONSOL Energy formally assesses both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in the fair values or the cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

CONSOL Energy has entered into forward and option contracts on various commodities to manage the price risk associated with the forecasted revenues from those commodities. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodities.

As of December 31, 2009, the total notional amount of the Company’s outstanding natural gas forward contracts was 85.1 billion cubic feet. These forward contracts are forecasted to settle through December 31, 2012 and meet the criteria for cash flow hedge accounting. During the next year, $60,307 of unrealized gain is expected to be reclassified from Other Comprehensive Income and into earnings. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

As of December 31, 2009, CONSOL Energy did not have any outstanding coal sales options. For the years ended December 31, 2009 and 2008, CONSOL Energy recognized, in Other Income on the Consolidated Statement of Income, a gain of $2,368 and a loss of ($335), respectively, for the coal sales options which were not designated as hedging instruments.

The fair value of CONSOL Energy’s derivative instruments at December 31, 2009 is as follows:


	Derivatives As of December 31, 2009
	Balance Sheet Location	Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps	Prepaid Expense	$	99,265
Natural Gas Price Swaps	Other Assets		18,218

Total derivatives designated as hedging instruments		$	117,483

The effect of derivative instruments on the Consolidated Statement of Income for the year ended December 31, 2009 is as follows:


Derivative in Cash Flow Hedging Relationship	Amount of Gain(Loss) Recognized in OCI on Derivative 2009			Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income 2009		Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative 2009
Natural Gas Price Swaps	$	(185,862	)	Outside Sales	$	239,956	Outside Sales	$	(962	)

Total	$	(185,862	)		$	239,956		$	(962	)

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The fair value of CONSOL Energy’s derivative instruments at December 31, 2008 is as follows:


	Asset Derivatives 2008			Liability Derivatives 2008
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps	Prepaid Expense	$	150,564
	Other Assets		55,945

Total derivatives designated as hedging instruments		$	206,509		$	—

Derivative not designated as hedging instruments
Coal Sales Options			—	Other Liabilities		(1,937	)

Total derivatives not designated as hedging instruments		$	—		$	(1,937	)

Total Derivatives		$	206,509		$	(1,937	)

The effect of derivative instruments on the consolidated statement of income for the year ended December 31, 2008 is as follows:


Derivative in Cash Flow Hedging Relationship	Amount of Gain(Loss) Recognized in OCI on Derivative 2008			Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income 2008			Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative 2008
Natural Gas Price Swaps	$	(118,652	)	Outside Sales	$	(947	)	Outside Sales	$	952

Total	$	(118,652	)		$	(947	)		$	952

Note 24—Commitments and Contingent Liabilities:

CONSOL Energy and its subsidiaries are 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 2008, the Pennsylvania Department of Conservation and Natural Resources (Commonwealth) filed a six-count Complaint in the Court of Common Pleas of Allegheny County, Pennsylvania, claiming that the Company’s underground longwall mining activities caused cracks and seepage damage to the Ryerson Park Dam, thereby eliminating the Ryerson Park Lake. The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resources damages totaling $58,000. The Court stayed the proceedings in the state court, holding that the Commonwealth should pursue administrative agency review of the claim. Furthermore, the Court found that the Commonwealth could not recover natural resources damages under applicable law. The issue of whether the dam was damaged by subsidence is being reviewed by the

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(Dollars in thousands, except per share data)

Department of Environmental Protection (DEP). If the DEP determines that there is causation, a second phase will be set to determine the remedy. As to the underlying claim, the Company believes it is not responsible for the damage to the dam and that numerous grounds exist upon which to attack the propriety of the claims. The Company intends to vigorously defend the case. However, it is reasonably possible that the ultimate liability in the future with respect to these claims may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 22,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi, New Jersey and Illinois. 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. Past 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 and 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 was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under Superfund legislation with respect to the Ward Transformer site in Wake County, North Carolina. At that time, the EPA also identified 38 other PRPs for the Ward Transformer site. The EPA, CONSOL Energy and two other PRPs entered into an administrative Settlement Agreement and Order of Consent, requiring those PRPs to undertake and complete a PCB soil removal action, at and in the vicinity of the Ward Transformer property. Another party joined the participating PRPs and reduced CONSOL Energy’s interim allocation share from 46% to 32%. In June 2008, while conducting the PCB soil excavation on the Ward property, it was determined that PCBs have migrated onto adjacent properties.

The current estimated cost of remedial action for the area CONSOL Energy was originally named a PRP, including payment of the EPA’s past and future cost, is approximately $55,000. The current estimated cost of the most likely remediation plan for one of the additional areas discovered is approximately $10,000, although the removal action plan is not yet approved by the EPA. Also, in September 2008, the EPA notified CONSOL Energy and 60 other PRPs that there were additional areas of potential contamination allegedly related to the Ward Transformer Site. Current estimates of the cost or potential range of cost for this area are not yet available. There was $3,422, $7,080 and $1,780 of expense recognized in Cost of Goods Sold and Other Charges for the years ended December 31, 2009, 2008 and 2007, respectively. CONSOL Energy funded $5,500, $6,000 and $1,256 in the years ended December 31, 2009, 2008 and 2007, respectively, to an independent trust established for this remediation. The remaining liability at December 31, 2009 of $5,914 is reflected in Other Accrued Liabilities at December 31, 2009.

As of April 30, 2009, CONSOL Energy and the other participating PRPs had asserted CERCLA cost recovery and contribution claims against approximately 225 nonparticipating PRPs to recover a share of the costs

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(Dollars in thousands, except per share data)

incurred and to be incurred to conduct the removal actions at the Ward Site. CONSOL Energy’s portion of probable recoveries from settled claims is estimated to be $3,620. Accordingly, an asset has been included in Other Assets for these claims. We cannot predict the ultimate outcome of this Superfund site; however, it is reasonably possible that payments in the future with respect to this lawsuit may be material to the financial position, results of operations or cash flows of CONSOL Energy.

As part of conducting mining activities at the Buchanan Mine, our subsidiary, Consolidation Coal Company (“CCC”), has to remove water from the mine. Several actions have arisen with respect to the removal of naturally accumulating and pumped water from the Buchanan Mine:

Yukon Pocahontas Coal Company, Buchanan Coal Company and Sayers-Pocahontas Coal Company filed an action on March 22, 2004 against CCC which is presently pending in the Circuit Court of Buchanan County, Virginia (the “Yukon Action”). The action is related to CCC’s depositing of untreated water from its Buchanan Mine into the void spaces of nearby mines of one of our other subsidiaries, Island Creek Coal Company (“ICCC”). The plaintiffs are seeking to stop CCC from depositing any additional water in these areas, to require CCC to remove the water that is stored there along with any remaining impurities, to recover over $3,252,000 for alleged damages to the coal and gas estates and punitive damages in the amount of $350. Plaintiffs have also asserted damage claims of $150,000 against CONSOL Energy, CNX Gas Company, LLC and ICCC. The Yukon group has recently filed a demand for arbitration (the “2008 Arbitration”) against ICCC which makes similar claims relating to breach of the lease for water deposits and lost coal claims.

CCC obtained a revision to its environmental permit to deposit water from its Buchanan Mine into void spaces of VP3, and to permit the discharge of water into the nearby Levisa River under controlled conditions. Plaintiffs in the Yukon Action along with the Town of Grundy, Virginia, Buchanan County Board of Supervisors, and others have appealed the revision.

We believe that CCC has and continues to have the right to deposit mine water from Buchanan Mine into void spaces at nearby mines. We also believe CCC was properly issued environmental permits to deposit water from the Buchanan Mine into VP3 and to discharge water into the Levisa River. CCC and the other named CONSOL Energy defendants in the Yukon Action deny all liability and intend to vigorously defend the action filed against them in connection with the removal and deposit of water from the Buchanan Mine, as well as environmental permits issued to CCC. Consequently, we have not recognized any liability related to these actions. However, if a temporary or permanent injunction were to be issued against CCC, if the environmental permits were temporarily suspended or revoked, or if damages were awarded to plaintiffs, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2006, CONSOL Energy and CCC were served with a summons in the name of the Commonwealth of Virginia with the Circuit Court of Buchanan County, Virginia regarding a special grand jury presentment in response to citizens’ complaints that noise resulting from the ventilation fan at the Buchanan Mine constitutes a public nuisance. CONSOL Energy and CCC deny that the operation of the ventilation fan is a public nuisance and intend to vigorously defend this proceeding. However, if the operation of the ventilation fan is ordered to be stopped, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In, 2007 Bluestone Coal Corporation filed a lawsuit against the Company and its subsidiary, CNX Land Resources, in the United States District Court for the Southern District of West Virginia. The suit alleges that the Company breached a contract that allegedly provides Bluestone with an option to lease coal reserves within a seven-and-one-half mile radius of Bishop, WV and seeks damages of $1,200,000. The writing relied upon only

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CONSOL ENERGY INC. AND SUBSIDIARIES

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(Dollars in thousands, except per share data)

refers to a right of first refusal, rather than an option. The lawsuit has been settled. The terms of the settlement are confidential, but include CONSOL Energy granting to Bluestone the option to acquire certain mining assets and reserves. The settlement did not materially impact the financial position, results of operations or cash flows of CONSOL Energy.

South Carolina Electric & Gas Company (“SCE&G”), a utility, has demanded arbitration, seeking $36,000 in damages against CONSOL of Kentucky and CONSOL Energy Sales Company. SCE&G claims it suffered damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. The Company counterclaimed against SCE&G for $9,400 for terminating coal shipments under the sales agreement which SCE&G had agreed could be made up in 2009. A hearing on the claims is scheduled for October 11, 2010. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them. However, if damages were awarded to SCE&G, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2009, a fish kill occurred in Dunkard Creek, which is a creek with segments in both Pennsylvania and West Virginia. The fish kill was caused by the growth of golden brown algae in the creek, which appears to be an invasive species. Our subsidiary, CCC, discharges treated mine water into Dunkard Creek from its Blacksville No. 2 Mine and from its Loveridge Mine. The discharges have levels of chlorides that cause Dunkard Creek to exceed West Virginia in-stream water quality standards. Prior to the fish kill, CCC was subject to an Agreed Order with the West Virginia Department of Environmental Protection that sets forth a schedule for compliance with these in-stream chloride limits. On December 18, 2009, the West Virginia Department of Environmental Protection issued a unilateral Order that imposes additional conditions on CCC's discharges into Dunkard Creek and requires CCC to develop a plan for long-term treatment of those and other high-chloride discharges. The Dunkard Creek fish kill is being investigated by several agencies, including the West Virginia Department of Environmental Protection, the West Virginia Department of Natural Resources, the Pennsylvania Department of Environmental Protection, and the Pennsylvania Fish and Boat Commission. The U.S. Environmental Protection Agency is also involved. We are cooperating with these investigations. We do not believe that there is a connection between the fish kill and our discharge of water into Dunkard Creek, but the investigation of the matter is continuing. If such a causal connection were established or if we are required to comply with in-stream chloride limits on an accelerated basis, it is reasonably possible that the liabilities or costs that could be incurred by CONSOL Energy in the future with respect to these matters may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

In 2007, GeoMet, Inc. and certain of its affiliates filed a lawsuit against CONSOL Energy and certain of its affiliates, including CNX Gas Company LLC, in the Circuit Court for the County of Tazewell, Virginia. The lawsuit alleges, among other things, that the defendants have violated the Virginia Antitrust Act in their dealings with GeoMet in southwest Virginia. The complaint, as amended, seeks injunctive relief, compensatory damages of $385,600 and treble damages. CNX Gas continues to believe this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; 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 CNX Gas.

In 2009, CNX Gas received a civil investigative demand for information and documents from the Attorney General of the Commonwealth of Virginia regarding the company's exploration, production, transportation and sale of coalbed methane gas in Virginia. According to the request, the Attorney General is investigating whether the company may have violated the Virginia Antitrust Act. The request for information does not constitute the commencement of legal proceedings and does not make any specific allegations against the company. CNX Gas

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(Dollars in thousands, except per share data)

does not believe that it has violated the Virginia Antitrust Act and CNX Gas is cooperating with the Attorney General's investigation.

The Company is a party to a case filed in 2007 captioned Earl Kennedy (and others) v. CNX Gas and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas. The complaint, as amended, seeks injunctive relief, including having CNX Gas be removed from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal that dismissal. CNX Gas believes this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; 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 CNX Gas.

In 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a lawsuit against CNX Gas Company LLC in the Circuit Court of the County of Buchanan for the year 2002; the county has since filed and served three substantially similar cases for years 2003, 2004 and 2005. These cases have been consolidated. The complaint alleges that CNX Gas’ calculation of the license tax on the basis of the wellhead value (sales price less post production costs) rather than the sales price is improper. For the period from 1999 through mid 2002, CNX Gas paid the tax on the basis of the sales price, but we have filed a claim for a refund for these years. Since 2002, we have continued to pay Buchanan County taxes based on our method of calculating the taxes. This litigation has been settled on terms that do not materially impact the financial position or the results of operations of CNX Gas or CONSOL Energy.

In 2007, the assigned operators, including subsidiaries of CONSOL Energy, and the Combined Fund entered into a settlement agreement that resolved all issues relating to the calculation and imposition of higher per beneficiary premium rates. The settlement agreement provides for full reimbursement of the higher per beneficiary premium rate. The settlement agreement provided for full reimbursement of higher per beneficiary premium rate previously paid by CONSOL Energy subsidiaries and related interest. In the year ended December 31, 2007, CONSOL Energy received $30,389 which was reflected as a reduction to cost of goods sold and other charges.

In 2007, production at the Buchanan Mine was suspended after several roof falls damaged some of the ventilation controls inside the mine. Production resumed in March 2008. The incident was covered under our property and business interruption insurance policy, subject to certain deductibles. Business interruption recoveries of $50,000 were recognized as Other Income in the year ended December 31, 2008, $42,000 in the coal segment and $8,000 in the gas segment.

In 2008, the Emergency Economic Stabilization Act of 2008 (the EESA Act) was signed into law. The EESA Act contained a section that authorizes certain coal producers and exporters who had filed a Black Lung Excise Tax (BLET) return on or after October 1, 1990, to request a refund of the BLET paid on export sales during these years. The EESA Act requires that the U.S. Treasury refund a coal producer or exporter an amount equal to the BLET erroneously paid on export sales in prior years along with interest computed at the statutory rates applicable to overpayments. In the year ended December 31, 2008, CONSOL Energy recognized a receivable related to these refunds of $58,983, including interest of $32,444. In relation to this receivable, CONSOL Energy recognized a payable of $3,187 that was owed to third parties upon collection of the refunds. The receivable was collected and the related payables were paid in the year ended December 31, 2009.

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(Dollars in thousands, except per share data)

At December 31, 2009, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credits are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.


	Amount and Duration of Commitments
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	193,017	$	193,017	$	—	$	—	$	—
Environmental		63,502		63,502		—		—		—
Gas		14,913		14,913		—		—		—
Other		11,914		11,850		64		—		—

Total Letters of Credit		283,346		283,282		64		—		—

Surety Bonds:
Employee-Related		193,251		193,251		—		—		—
Environmental		345,955		345,782		173		—		—
Gas		4,442		4,442		—		—		—
Other		9,726		9,713		13		—		—

Total Surety Bonds		553,374		553,188		186		—		—

Guarantees:
Coal		111,088		79,890		25,198		1,000		5,000
Gas		56,156		30,479		22,577		—		3,100
Other		277,694		42,925		71,617		51,991		111,161

Total Guarantees		444,938		153,294		119,392		52,991		119,261

Total Commitments	$	1,281,658	$	989,764	$	119,642	$	52,991	$	119,261

CONSOL Energy and CNX Gas enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheets. As of December 31, 2009, the purchase obligations for each of the next five years were as follows:


Obligations Due	Amount
Less than 1 year	$	69,228
1 – 3 years		55,680
3 – 5 years		49,934
More than 5 years		303,347

Total Purchase Obligations	$	478,189

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(Dollars in thousands, except per share data)

Costs related to major equipment purchases under these purchase obligations was $89,261, $10,957 and $15,886 for the years ended December 31, 2009, 2008 and 2007. Firm transportation expense under these purchase obligations was $21,668, $11,476 and $9,390 for the years ended December 31, 2009, 2008 and 2007 respectively. Expenses related to gas drilling purchase obligations were $585 for the year ended December 31, 2009. Expenses related to other operating goods and services under these purchase obligations was $120 and $60 for the years ended December 31, 2009 and 2008.

Employee-related financial guarantees have primarily been provided to support the United Mine Workers’ of America’s 1992 Benefit Plan and various state workers’ compensation self-insurance programs. Environmental financial guarantees have primarily been provided to support various performance bonds related to reclamation and other environmental issues. Gas financial guarantees have primarily been provided to support various performance bonds related to land usage and restorative issues. Other guarantees have been extended to support insurance policies, legal matters and various other items necessary in the normal course of business. Other guarantees have also been provided to promise the full and timely payments to lessors of mining equipment and support various other items necessary in the normal course of business.

Note 25—Segment Information:

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, 2009, the Northern Appalachian aggregated segment includes the following mines: Blacksville #2, Robinson Run, McElroy, Loveridge, Bailey, Enlow Fork, Mine 84 and Shoemaker. For the year ended December 31, 2009, the Central Appalachian aggregated segment includes the following mines: Jones Fork Complex, the Miller Creek Complex, the Fola Complex and the Terry Eagle Complex. For the year ended December 31, 2009, the Metallurgical aggregated segment includes the following mines: Buchanan and Amonate Complex. 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. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities, including rentals of buildings and flight operations. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Certain reclassifications of 2008 and 2007 segment information have been made to conform to the 2009 presentation.

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(Dollars in thousands, except per share data)

Industry segment results for the year ended December 31, 2009 are:


	Northern Appalachian		Central Appalachian		Metallurgical		Other Coal			Total Coal		Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	2,545,779	$	460,973	$	248,543	$	154,591		$	3,409,886	$	628,929	$	272,976	$	—		$	4,311,791	(A)
Sales—Purchased Gas		—		—		—		—			—		7,040		—		—			7,040
Sales—Gas Royalty Interests		—		—		—		—			—		40,951		—		—			40,951
Freight—outside		—		—		—		148,907			148,907		—		—		—			148,907
Intersegment transfers		—		—		—		—			—		1,671		152,375		(154,046	)		—

Total Sales and Freight	$	2,545,779	$	460,973	$	248,543	$	303,498		$	3,558,793	$	678,591	$	425,351	$	(154,046	)	$	4,508,689

Earnings (Loss) Before Income Taxes	$	666,476	$	30,401	$	74,689	$	(155,764	)	$	615,802	$	261,835	$	9,983	$	(99,275	)	$	788,345	(B)

Segment assets										$	4,672,508	$	2,171,495	$	317,004	$	564,394		$	7,725,401	(C)

Depreciation, depletion and amortization										$	310,346	$	107,251	$	19,820	$	—		$	437,417

Capital expenditures										$	580,401	$	322,126	$	17,553	$	—		$	920,080

(A)	There were no sales to customers aggregating over 10% of total revenue in 2009.

(B)	Includes equity in earnings of unconsolidated affiliates of $5,663, $637 and $9,408 for Coal, Gas and All Other, respectively.

(C)	Includes investments in unconsolidated equity affiliates of $12,569, $24,590 and $46,374 for Coal, Gas and All Other, respectively.

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(Dollars in thousands, except per share data)

Industry segment results for the year ended December 31, 2008 are:


	Northern Appalachian		Central Appalachian			Metallurgical		Other Coal			Total Coal		Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	2,126,182	$	519,428		$	341,177	$	197,657		$	3,184,444	$	680,990	$	316,135	$	—		$	4,181,569	(D)
Sales—Purchased Gas		—		—			—		—			—		8,464		—		—			8,464
Sales—Gas Royalty Interests		—		—			—		—			—		79,302		—		—			79,302
Freight—outside		—		—			—		216,968			216,968		—		—		—			216,968
Intersegment transfers		—		—			—		—			—		7,337		145,856		(153,193	)		—

Total Sales and Freight	$	2,126,182	$	519,428		$	341,177	$	414,625		$	3,401,412	$	776,093	$	461,991	$	(153,193	)	$	4,486,303

Earnings (Loss) Before Income Taxes	$	323,348	$	(18,040	)	$	190,331	$	(88,601	)	$	407,038	$	385,954	$	18,526	$	(85,923	)	$	725,595	(E)

Segment assets											$	4,387,584	$	2,094,748	$	322,137	$	565,989		$	7,370,458	(F)

Depreciation, depletion and amortization											$	299,831	$	70,010	$	19,780	$	—		$	389,621

Capital expenditures											$	445,594	$	560,663	$	55,412	$	—		$	1,061,669

(D)	There were no sales to customers aggregating over 10% of total revenue in 2008.

(E)	Includes equity in earnings of unconsolidated affiliates of $2,534, $551 and $8,055 for Coal, Gas and All Other, respectively.

(F)	Includes investments in unconsolidated equity affiliates of $9,386, $25,204 and $38,406 for Coal, Gas and All Other, respectively. Also, included in the Coal segment is $58,983 of receivables related to the Emergency Economic Stabilization Act of 2008.

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(Dollars in thousands, except per share data)

Industry segment results for the year ended December 31, 2007 are:


	Northern Appalachian		Central Appalachian		Metallurgical		Other Coal			Total Coal		Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—outside	$	1,990,897	$	383,596	$	237,266	$	66,922		$	2,678,681	$	410,211	$	235,454	$	—		$	3,324,346	(G)
Sales—Purchased Gas		—		—		—		—			—		7,628		—		—			7,628
Sales—Gas Royalty Interests		—		—		—		—			—		46,586		—		—			46,586
Freight—outside		—		—		—		186,909			186,909		—		—		—			186,909
Intersegment transfers		—		—		—		—			—		6,242		129,648		(135,890	)		—

Total Sales and Freight	$	1,990,897	$	383,596	$	237,266	$	253,831		$	2,865,590	$	470,667	$	365,102	$	(135,890	)	$	3,565,469

Earnings (Loss) Before Income Taxes	$	353,104	$	32,451	$	65,080	$	(173,128	)	$	277,507	$	214,874	$	15,152	$	(78,576	)	$	428,957	(H)

Segment assets										$	4,039,513	$	1,378,709	$	253,792	$	536,076		$	6,208,090	(I)

Depreciation, depletion and amortization										$	257,349	$	48,961	$	18,405	$	—		$	324,715

Capital expenditures										$	681,408	$	304,088	$	54,342	$	—		$	1,039,838

(G)	There were no sales to customers aggregating over 10% in 2007.

(H)	Includes equity in earnings of unconsolidated affiliates of $1,027, $2,174 and $3,350 for Coal, Gas and All Other, respectively.

(I)	Includes investments in unconsolidated equity affiliates of $3,101, $56,865 and $34,900 for Coal, Gas and All Other, respectively.

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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Income:


	For the Years Ended December 31,
	2009			2008			2007
Total segment sales and freight from external customers	$	4,508,689		$	4,486,303		$	3,565,469
Other income not allocated to segments (Note 3)		113,186			166,142			196,728

Total Consolidated Revenue and Other Income	$	4,621,875		$	4,652,445		$	3,762,197

Earnings Before Income Taxes:
Segment Earnings Before Income Taxes for total reportable business segments	$	877,637		$	792,992		$	492,381
Segment Earnings (Loss) Before Income Taxes for all other businesses		9,983			18,526			15,152
Incentive compensation(J)		(35,071	)		(24,872	)		(26,770	)
Compensation from restricted stock unit grants, stock option expense and performance share unit expense(J)		(26,686	)		(21,807	)		(20,983	)
Interest income (expense), net and other non-operating activity(J)		(26,472	)		(39,244	)		(30,823	)
Corporate restructuring(J)		(4,378	)		—			—
Lease settlement(J)		(6,668	)		—			—

Earnings Before Income Taxes	$	788,345		$	725,595		$	428,957


	December 31,
	2009			2008			2007
Total Assets:
Segment assets for total reportable business segments	$	6,844,003		$	6,482,332		$	5,418,222
Segment assets for all other businesses		317,004			322,137			253,792
Items excluded from segment assets:
Cash and other investments(J)		65,025			136,951			9,978
Deferred tax assets		498,680			394,142			505,631
Recoverable income taxes		—			33,862			19,090
Bond issuance costs		689			1,034			1,377

Total Consolidated Assets	$	7,725,401		$	7,370,458		$	6,208,090

(J)	Excludes amounts specifically related to the gas segment.

157

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Enterprise-Wide Disclosures:

CONSOL Energy’s Revenues by geographical location:


	For the Years Ended December 31,
	2009		2008		2007
United States	$	4,026,619	$	3,841,665	$	3,077,573
Europe		298,262		462,291		332,280
South America		120,174		94,230		40,255
Canada		25,056		88,106		115,361
Other		38,578		11

Total Revenues and Freight from External Customers(K)	$	4,508,689	$	4,486,303	$	3,565,469

(K)	CONSOL Energy attributes revenue to individual countries based on the location of the customer.

CONSOL Energy’s Property, Plant and Equipment by geographical location are:


	December 31,
	2009		2008
United States	$	6,090,703	$	5,732,021
Canada		33,587		33,828
Belgium		—		123

	$	6,124,290	$	5,765,972

Note 26—Guarantor Subsidiaries Financial Information:

The payment obligations under the $250,000, 7.875 percent per annum notes due March 1, 2012 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by several subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (“SEC”), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, an 83.3% owned guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. CNX Gas is presented in a separate column in accordance with SEC Regulation S-X Rule 3-10. CNX Gas Corporation is a reporting company under Section 12(b) of the Securities Exchange Act of 1933, and as such, CNX Gas Corporation files its own financial statements with the Securities and Exchange Commission and those financial statements, when filed, are publicly available on Edgar. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other 100% owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

158

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Income Statement for the Year Ended December 31, 2009:


	Parent			CNX Gas Guarantor		Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	630,598	$	3,487,022		$	197,350	$	(3,179	)	$	4,311,791
Sales—Purchased gas		—			7,040		—			—		—			7,040
Sales—Gas Royalty Interest		—			40,951		—			—		—			40,951
Freight—Outside		—			—		148,907			—		—			148,907
Other Income (including equity earnings)		622,216			4,855		76,442			22,173		(612,500	)		113,186

Total Revenue and Other Income		622,216			683,444		3,712,371			219,523		(615,679	)		4,621,875
Cost of Goods Sold and Other Operating Charges		84,960			155,583		2,083,462			190,854		242,193			2,757,052
Purchased Gas Costs		—			6,442		—			—		—			6,442
Gas Royalty Interest		—			32,423		—			—		(47	)		32,376
Related Party Activity		7,052			—		132,106			1,495		(140,653	)		—
Freight Expense		—			—		148,907			—		—			148,907
Selling, General and Administrative Expense		—			99,526		118,287			1,287		(88,396	)		130,704
Depreciation, Depletion and Amortization		13,022			107,251		316,352			2,654		(1,862	)		437,417
Interest Expense		13,229			7,568		10,959			15		(352	)		31,419
Taxes Other Than Income		9,576			12,590		265,180			2,595		—			289,941
Black Lung Excise Tax Refund		—			—		(728	)		—		—			(728	)

Total Costs		127,839			421,383		3,074,525			198,900		10,883			3,833,530

Earnings (Loss) Before Income Taxes		494,377			262,061		637,846			20,623		(626,562	)		788,345
Income Taxes (Benefit)		(45,340	)		98,636		160,105			7,802		—			221,203

Net Income		539,717			163,425		477,741			12,821		(626,562	)		567,142
Less: Net Income Attributable to Noncontrolling Interest		—			1,037		(1,037	)		—		(27,425	)		(27,425	)

Net Income Attributable to CONSOL Energy Inc. Shareholders	$	539,717		$	164,462	$	476,704		$	12,821	$	(653,987	)	$	539,717

159

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Balance Sheet for December 31, 2009:


	Parent		CNX Gas Guarantor			Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	59,549	$	1,124		$	3,764		$	1,170	$	—		$	65,607
Accounts and Notes Receivable:
Trade		—		43,421			113			273,926		—			317,460
Other		4,781		975			3,281			6,946		—			15,983
Inventories		—		—			262,755			44,842		—			307,597
Deferred Income Taxes		108,254		(34,871	)		—			—		—			73,383
Prepaid Expenses		18,979		103,094			36,767			2,166		—			161,006

Total Current Assets		191,563		113,743			306,680			329,050		—			941,036
Property, Plant and Equipment:
Property, Plant and Equipment		162,145		2,409,751			8,082,159			27,900		—			10,681,955
Less-Accumulated Depreciation, Depletion and Amortization		82,733		433,201			4,022,295			19,436		—			4,557,665

Property, Plant and Equipment—Net		79,412		1,976,550			4,059,864			8,464		—			6,124,290
Other Assets:
Deferred Income Taxes		759,790		(334,493	)		—			—		—			425,297
Investment in Affiliates		4,399,823		24,591			797,269			3,921		(5,142,071	)		83,533
Other		84,736		21,627			33,216			11,666		—			151,245

Total Other Assets		5,244,349		(288,275	)		830,485			15,587		(5,142,071	)		660,075

Total Assets	$	5,515,324	$	1,802,018		$	5,197,029		$	353,101	$	(5,142,071	)	$	7,725,401

Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	93,876	$	53,516		$	114,872		$	7,296	$	—		$	269,560
Accounts Payable (Recoverable)-Related Parties		2,117,616		5,171			(2,378,119	)		255,332		—			—
Short-Term Notes Payable		415,000		57,850			—			—		—			472,850
Current Portion of Long-Term Debt		501		8,616			35,853			424		—			45,394
Accrued Income Taxes		27,944		31,765			(31,765	)		—		—			27,944
Other Accrued Liabilities		546,066		25,455			34,569			6,748		—			612,838

Total Current Liabilities		3,201,003		182,373			(2,224,590	)		269,800		—			1,428,586
Long-Term Debt:		250,255		65,690			106,369			594		—			422,908
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions		—		3,642			2,675,704			—		—			2,679,346
Pneumoconiosis		—		—			184,965			—		—			184,965
Mine Closing		—		—			397,320			—		—			397,320
Gas Well Closing		—		8,312			77,680			—		—			85,992
Workers’ Compensation		—		—			152,486			—		—			152,486
Deferred Revenue		—		—			—			—		—			—
Salary Retirement		189,697		—			—			—		—			189,697
Reclamation		—		—			27,105			—		—			27,105
Other		88,821		35,101			8,595			—		—			132,517

Total Deferred Credits and Other Liabilities		278,518		47,055			3,523,855			—		—			3,849,428
Consol Energy Inc. Stockholders’ Equity		1,785,548		1,511,270			3,787,025			82,707		(5,381,002	)		1,785,548
Noncontrolling Interest		—		(4,370	)		4,370			—		238,931			238,931

Total Liabilities and Stockholders’ Equity	$	5,515,324	$	1,802,018		$	5,197,029		$	353,101	$	(5,142,071	)	$	7,725,401

160

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Condensed Statement of Cash Flows

For the Year Ended December 31, 2009:


	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non-Guarantors			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	64,095		$	360,163		$	523,596		$	(2,403	)	$	—	$	45,451

Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(336,447	)	$	(583,633	)	$	—		$	—	$	(920,080	)
Investment in Equity Affiliates		—			1,250			3,605			—			—		4,855
Proceeds from Sale of Assets		—			288			69,596			—			—		69,884

Net Cash Used in Investing Activities	$	—		$	(334,909	)	$	(510,432	)	$	—		$	—	$	(845,341	)

Cash Flows from Financial Activities:
Dividends Paid	$	(72,292	)	$	—		$	—		$	—		$	—	$	(72,292	)
Proceeds from Revolver		(70,000	)		(14,850	)		—			—			—		(84,850	)
Other Financing Activities		5,275			(11,206	)		(9,481	)		(461	)		—		(15,873	)

Net Cash Provided By (Used in) Financing Activities	$	(137,017	)	$	(26,056	)	$	(9,481	)	$	(461	)	$	—	$	(173,015	)

161

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Income Statement for the Year Ended December 31, 2008:


	Parent			CNX Gas Guarantor		Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	688,325	$	3,231,163		$	271,613	$	(9,532	)	$	4,181,569
Sales—Purchased gas		—			8,464		—			—		—			8,464
Sales—Gas Royalty Interest		—			79,302		—			—		—			79,302
Freight—Outside		—			—		216,968			—		—			216,968
Other Income (including equity earnings)		513,910			13,330		117,487			38,375		(516,960	)		166,142

Total Revenue and Other Income		513,910			789,421		3,565,618			309,988		(526,492	)		4,652,445
Cost of Goods Sold and Other Operating Charges		72,790			132,254		2,312,477			112,402		213,280			2,843,203
Purchased Gas Costs		—			8,175		—			—		—			8,175
Gas Royalty Interest		—			74,041		—			—		(79	)		73,962
Related Party Activity		5,622			—		39,325			155,304		(200,251	)		—
Freight Expense		—			—		216,968			—		—			216,968
Selling, General and Administrative Expense		—			80,246		39,660			4,637		—			124,543
Depreciation, Depletion and Amortization		9,382			70,010		300,635			11,485		(1,891	)		389,621
Interest Expense		17,888			7,820		10,312			498		(335	)		36,183
Taxes Other Than Income		5,887			24,146		250,398			9,559		—			289,990
Black Lung Excise Tax Refund		—			—		(55,795	)		—		—			(55,795	)

Total Costs		111,569			396,692		3,113,980			293,885		10,724			3,926,850

Earnings (Loss) Before Income Taxes		402,341			392,729		451,638			16,103		(537,216	)		725,595
Income Taxes (Benefit)		(40,129	)		153,656		120,315			6,092		—			239,934

Net Income		442,470			239,073		331,323			10,011		(537,216	)		485,661
Less: Net Income Attributable to Noncontrolling Interest		—			—		—			—		(43,191	)		(43,191	)

Net Income Attributable to CONSOL Energy Inc. Shareholders	$	442,470		$	239,073	$	331,323		$	10,011	$	(580,407	)	$	442,470

162

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Balance Sheet for December 31, 2008:


	Parent		CNX Gas Guarantor			Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	132,471	$	1,926		$	81		$	4,034	$	—		$	138,512
Accounts and Notes Receivable:
Trade		—		61,764			35			159,930		—			221,729
Other		1,767		3,080			68,910			5,795		—			79,552
Inventories		—					184,140			43,670		—			227,810
Recoverable Income Taxes		3,560		30,302			—								33,862
Deferred Income Taxes		115,599		(55,000	)		—			—		—			60,599
Prepaid Expenses		23,612		152,786			40,409			4,943		—			221,750

Total Current Assets		277,009		194,858			293,575			218,372		—			983,814
Property, Plant and Equipment:
Property, Plant and Equipment		175,027		2,113,570			7,606,735			84,956		—			9,980,288
Less-Accumulated Depreciation, Depletion and Amortization		71,781		322,470			3,793,378			26,687		—			4,214,316

Property, Plant and Equipment—Net		103,246		1,791,100			3,813,357			58,269		—			5,765,972
Other Assets:
Deferred Income Taxes		664,881		(331,338	)		—			—		—			333,543
Investment in Affiliates		3,734,125		25,204			930,708			1,102		(4,618,143	)		72,996
Other		77,253		58,811			34,521			43,548		—			214,133

Total Other Assets		4,476,259		(247,323	)		965,229			44,650		(4,618,143	)		620,672

Total Assets	$	4,856,514	$	1,738,635		$	5,072,161		$	321,291	$	(4,618,143	)	$	7,370,458

Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	87,734	$	100,565		$	159,677		$	37,221	$	—		$	385,197
Accounts Payable (Recoverable)- Related Parties		1,853,629		2,234			(1,992,924	)		137,061		—			—
Short-Term Notes Payable		485,000		72,700			—			—		—			557,700
Current Portion of Long-Term Debt		1,473		8,462			12,093			373		—			22,401
Other Accrued Liabilities		410,086		42,089			84,417			9,850		—			546,442

Total Current Liabilities		2,837,922		226,050			(1,736,737	)		184,505		—			1,511,740
Long-Term Debt:		252,145		74,682			140,956			568		—			468,351
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions		—		2,728			2,490,616			—		—			2,493,344
Pneumoconiosis		—		—			190,261			—		—			190,261
Mine Closing		—		—			393,112			11,517		—			404,629
Gas Well Closing		—		7,401			73,153			—		—			80,554
Workers’ Compensation		—		—			128,477			—		—			128,477
Salary Retirement		194,567		—			—			—		—			194,567
Reclamation		—		—			15,363			22,830		—			38,193
Other		109,693		42,900			7,698			25,705		—			185,996

Total Deferred Credits and Other Liabilities		304,260		53,029			3,298,680			60,052		—			3,716,021
CONSOL Energy Inc. Stockholders’ Equity		1,462,187		1,384,874			3,370,895			74,533		(4,830,302	)		1,462,187
Noncontrolling Interest		—		—			—			—		212,159			212,159

Total Liabilities and Stockholders’ Equity	$	4,856,514	$	1,738,635		$	5,073,794		$	319,658	$	(4,618,143	)	$	7,370,458

163

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Condensed Statement of Cash Flows

For the Year Ended December 31, 2008:


	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non-Guarantors			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	34,647		$	447,375		$	510,475		$	36,967		$	—	$	1,029,464

Cash Flows from Investing
Capital Expenditures	$	(11,371	)	$	(560,663	)	$	(464,603	)	$	(25,032	)	$	—	$	(1,061,669	)
Investment in Equity Affiliates		—			1,081			798			—			—		1,879
Purchase of Stock in Subsidiary								(67,259	)							(67,259	)
Proceeds from Sale of Assets		—			450			27,743			—			—		28,193

Net Cash Used in Investing Activities	$	(11,371	)	$	(559,132	)	$	(503,321	)	$	(25,032	)	$	—	$	(1,098,856	)

Cash Flows from Financial Activities:
Dividends Paid	$	(72,957	)	$	—		$	—		$	—		$	—	$	(72,957	)
Proceeds from Revolver		237,500			72,700			—			—			—		310,200
Purchase of Treasury Stock		(97,794	)		—			—			—			—		(97,794	)
Other Financing Activities		37,218			8,935			(8,364	)		(10,985	)		—		26,804

Net Cash Provided By (Used in) Financing Activities	$	103,967		$	81,635		$	(8,364	)	$	(10,985	)	$	—	$	166,253

164

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Income Statement for the Year Ended December 31, 2007:


	Parent			CNX Gas Guarantor		Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	416,453	$	2,718,493		$	201,018	$	(11,618	)	$	3,324,346
Sales—Purchased gas		—			7,628		—			—		—			7,628
Sales—Gas Royalty Interest		—			46,586		—			—		—			46,586
Freight—Outside		—			—		186,909			—		—			186,909
Other Income (including equity earnings)		333,581			8,815		141,735			40,093		(327,496	)		196,728

Total Revenue and Other Income		333,581			479,482		3,047,137			241,111		(339,114	)		3,762,197
Cost of Goods Sold and Other Operating Charges		63,899			102,278		1,916,159			61,864		207,800			2,352,000
Purchased Gas Costs		—			7,162		—			—		—			7,162
Gas Royalty Interest		—			40,011		—			—		(90	)		39,921
Related Party Activity		(4,601	)		—		87,459			134,213		(217,071	)		—
Freight Expense		—			—		186,909			—		—			186,909
Selling, General and Administrative Expense		—			54,825		51,029			2,810		—			108,664
Depreciation, Depletion and Amortization		7,666			48,961		259,825			10,343		(2,080	)		324,715
Interest Expense		24,932			5,606		(250	)		563		—			30,851
Taxes Other Than Income		5,790			—		246,177			6,959		—			258,926
Black Lung Excise Tax Refund		—			—		24,092			—		—			24,092

Total Costs		97,686			258,843		2,771,400			216,752		(11,441	)		3,333,240

Earnings (Loss) Before Income Taxes		235,895			220,639		275,737			24,359		(327,673	)		428,957
Income Taxes (Benefit)		(31,887	)		84,961		73,848			9,215		—			136,137

Net Income		267,782			135,678		201,889			15,144		(327,673	)		292,820
Less: Net Income Attributable to Noncontrolling Interest		—			—		—			—		(25,038	)		(25,038	)

Net Income Attributable to CONSOL Energy Inc. Shareholders	$	267,782		$	135,678	$	201,889		$	15,144	$	(352,711	)	$	267,782

165

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Condensed Statement of Cash Flows

For the Year Ended December 31, 2007:


	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non-Guarantors			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	(258,800	)	$	272,448		$	649,136		$	21,249		$	—	$	684,033

Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(348,631	)	$	(372,424	)	$	(22,059	)	$	—	$	(743,114	)
Acquisition of AMVEST		—			—			(296,724	)		—			—		(296,724	)
Investment in Equity Affiliates		—			(5,783	)		(1,274	)		—			—		(7,057	)
Purchase of Stock in Subsidiary		—			—			(10,000	)		—			—		(10,000	)
Proceeds from Sale of Assets		—			187			83,754			850			—		84,791

Net Cash Used in Investing Activities	$	—		$	(354,227	)	$	(596,668	)	$	(21,209	)	$	—	$	(972,104	)

Cash Flows from Financial Activities:
Dividends Paid	$	(56,475	)	$	—		$	—		$	—		$	—	$	(56,475	)
Proceeds from Revolver		247,500			—			—			—			—		247,500
Purchase of Treasury Stock		(80,157	)		—			—			—			—		(80,157	)
Payments on Long Term Notes		—			—			(45,000	)		—			—		(45,000	)
Other Financing Activities		42,906			6,654			(7,589	)		(2,000	)		—		39,971

Net Cash Provided By (Used in) Financing Activities	$	153,774		$	6,654		$	(52,589	)	$	(2,000	)	$	—	$	105,839

Supplemental Coal Data (unaudited):


	Millions of Tons For the Year Ended December 31,
	2009		2008		2007		2006		2005
Proved and probable reserves at beginning of period	4,543		4,526		4,272		4,546		4,509
Purchased reserves	5		—		177		3		56
Reserves sold in place	(3	)	(12	)	(33	)	(2	)	(2	)
Production	(59	)	(65	)	(65	)	(67	)	(69	)
Revisions and other changes	34		94		175		(208	)	52

Consolidated proved and probable reserves at end of period*	4,520		4,543		4,526		4,272		4,546

Proportionate share of proved and probable reserves of unconsolidated equity affiliates*	170		171		179		—		—

*	Proved and probable coal reserves are the equivalent of “demonstrated reserves” under the coal resource classification system of the U.S. Geological Survey. Generally, these reserves would be commercially mineable at year-end prices and cost levels, using current technology and mining practices.

166

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

CONSOL Energy’s coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2009, 898 million tons were assigned to mines either in production, temporarily idle, or under development. The proved and probable reserves at December 31, 2009 include 3,960 million tons of steam coal reserves, of which approximately 8 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million British thermal unit (Btu), and an additional 14 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. The reserves also include 560 million tons of metallurgical coal in consolidated reserves, of which approximately 62 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu, and an additional 37 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. A significant portion of this metallurgical coal can also serve the steam coal market.

Other Supplemental Information—Supplemental Gas Data (unaudited)

The following information was prepared in accordance with the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).”

Capitalized Costs:


	As of December 31,
	2009			2008
Proved properties	$	152,010		$	121,605
Unproved properties		271,553			220,848
Wells and related equipment		1,171,146			1,019,880
Gathering assets		804,212			740,396

Total Property, Plant and Equipment		2,398,921			2,102,729
Accumulated Depreciation, Depletion and Amortization		(429,966	)		(319,959	)

Net Capitalized Costs	$	1,968,955		$	1,782,770

Costs incurred for property acquisition, exploration and development (*):


	For the Years Ended December 31,
	2009		2008		2007
Property acquisitions and other changes
Proved properties	$	30,405	$	17,090	$	33,205
Unproved properties		50,705		119,168		80,313
Development		181,944		378,119		257,935
Exploration		46,023		68,495		16,503

Total	$	309,077	$	582,872	$	387,956

(*)	Includes costs incurred whether capitalized or expensed.

167

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Results of Operations for Producing Activities:


	For the Twelve Months Ended December 31,
	2009				2008				2007
	Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates
Production Revenue	$	630,598	$	—	$	688,325	$	—	$	416,452	$	2,755
Royalty Interest Gas Revenue		40,951		—		79,302		—		46,586		294
Purchased Gas Revenue		7,040		—		8,464		—		7,628		201

Total Revenue		678,589		—		776,091		—		470,666		3,250

Lifting Costs		55,285		—		67,653		—		38,721		679
Gathering Costs		95,687		—		83,752		—		61,798		630
Royalty Interest Gas Costs		32,423		—		74,041		—		40,011		294
Other Costs		45,795		—		34,078		—		19,772		646
Purchased Gas Costs		6,442		—		8,175		—		7,162		165
DD&A		107,251		—		70,010		—		48,961		294

Total Costs		342,883		—		337,709		—		216,425		2,708

Pre-tax Operating Income		335,706		—		438,382		—		254,241		542
Income Taxes		125,890		—		171,407		—		98,595		210

Results of Operations for Producing Activities excluding Corporate and Interest Costs	$	209,816	$	—	$	266,975	$	—	$	155,646	$	332

The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:


	For the Years Ended December 31,
	2009		2008		2007
Production in million cubic feet		94,415		76,562		58,249
Average gas sales price before effects of financial settlements (per thousand cubic feet)	$	4.15	$	8.99	$	6.87
Average effects of financial settlements (per thousand cubic feet)	$	2.53	$	—	$	0.33

Average gas sales price including effects of financial settlements (per thousand cubic feet)	$	6.68	$	8.99	$	7.20

Average lifting costs, excluding ad valorem and severance taxes (per thousand cubic feet)	$	0.48	$	0.58	$	0.39

During the years ended December 31, 2009, 2008 and 2007, we drilled 247, 534 and 370 net development wells, respectively. Of these wells drilled in the year ended December 31, 2009 there was one dry well. There were no dry wells in the years ended December 31, 2008 and 2007.

168

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

During the years ended December 31, 2009, 2008 and 2007, we drilled 18, 56 and 9 net exploratory wells, respectively. Of the wells drilled in the years ended December 31, 2009 and 2008, there were one and three dry wells, respectively. There were no dry wells in the year ended December 31, 2007.

At December 31, 2009, there were six development wells in the process of being drilled. Drilling activities are currently in progress to complete the drilling of these wells by the end of March 2010.

At December 31, 2009, there were ten exploratory wells in the process of being drilled. Drilling and evaluation activities will be in process throughout the 2010 period.

CNX Gas is committed to provide 44.1 Bcf of gas under existing contracts or agreements over the course of the next two years. CNX Gas expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.

Most of our development wells and proved 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. The following table sets forth the number of CNX Gas producing wells, developed acreage and undeveloped acreage at December 31, 2009:


	Gross	Net(1)
Producing Wells (including gob wells)	5,240	3,926
Proved Developed Acreage	260,327	254,753
Proved Undeveloped Acreage	56,090	54,298
Unproved Acreage	3,957,174	3,399,490

Total Acreage	4,273,591	3,708,541

(1)

Net acres do not include acreage attributable to the working interests of our principal joint venture partners and the portions of certain proved developed acreage attributable to property we have leased to third-party producers. Additional adjustments (either increases or decreases) may be required as we further develop title to and confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.

169

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Proved Oil and Gas Reserve Quantities:

The preparation of our gas reserve estimates are completed in accordance with CNX Gas’ prescribed internal control procedures, which include verification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer. Our 2009 gas reserve results were audited by Netherland, Sewell and Associates, Inc. The technical person primarily responsible for overseeing the audit of our reserves is a certified petroleum engineer. The gas reserve estimates are as follows:


	2009		2008				2007
	Consolidated Operations		Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates
Net Reserve Quantity (MMcfe)
Beginning reserves	1,422,046		1,339,909		3,584		1,263,293		2,200
Revisions(b)	177,004		(30,828	)	—		(25,036	)	221
Extensions and discoveries(c)	406,756		182,701		—		145,834		1,484
Production	(94,415	)	(76,562	)	—		(57,928	)	(321	)
Acquisition of remaining interest in equity affiliate	—		3,584		(3,584	)	—		—
Purchases of reserves in-place	—		3,242		—		13,746		—
Sale of reserves in-place	—		—		—		—		—

Ending reserves(a)	1,911,391		1,422,046		—		1,339,909		3,584

(a)

Proved developed and proved undeveloped gas reserves are defined by the Securities and Exchange Commission (SEC) Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX Gas cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas and coalbed methane gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.

(b)	Revisions are primarily due to efficiencies in operations which resulted in a reduction of operating costs, a comprehensive look into reservoir characterization and well performance.

(c)

Extensions and discoveries are due to the addition of our Marcellus Shale acreage and approvals from the Oil & Gas Board in Virginia to drill and complete wells on tighter spacing. Extensions and discoveries also include 120,933 MMcfe as a result of initially applying the amendments of ASC 932 in ASU 2010-03 related to capturing proved undeveloped locations more than one location away if reliable technology can be demonstrated.

170

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)


	2009			2008			2007
	All Products	Natural Gas mmcf	Oil mmcfe	All Products	Natural Gas mmcf	Oil mmcfe	All Products	Natural Gas mmcf	Oil mmcfe
Proved developed reserves (consolidated entities only)
Beginning of year	783,290	783,010	280	667,726	667,443	283	609,700	609,538	162

End of year	1,040,257	1,039,052	1,205	783,290	783,010	280	667,726	667,443	283

Proved undeveloped reserves (consolidated entities only)
Beginning of year	638,756	638,756	—	672,183	672,183	—	653,593	653,593	—

End of year	871,134	871,134	—	638,756	638,756	—	672,183	672,183	—


	For the Year Ended December 31, 2009
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves	638,756
Undeveloped reserves transferred to developed(a)	(118,145	)
Revisions	27,601
Extension and discoveries	322,922

Ending proved undeveloped reserves(b)	871,134

(a)	During 2009, various exploration and development drilling and evaluations were completed. Approximately, $45,326 of capital was spent in the year ended December 31, 2009 related to undeveloped reserves that were transferred to developed.

(b)

Included in proved undeveloped reserves at December 31, 2009 are approximately 120,000 MMcfe of reserves that have been reported for more than five years that relate specifically to CONSOL Energy’s Buchanan Mine. These undeveloped reserves will be developed in order to de-gas the mine ahead of longwall mining.

The following table represents the capitalized exploratory well cost activity as indicated:


	December 31, 2009
Costs pending the determination of proved reserves at December 31, 2009(a)
Less than one year	$	156
More than one year but less than five years		5,454
More than five years		2,627

Total	$	8,237

(a)	Costs held in exploratory for more than one year represent exploration wells away from existing infrastructure. The additional planned exploration expenditures will allow us to invest in infrastructure to support these fields.

171

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)


	For the Years Ended December 31,
	2009		2008		2007
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves	$	52,332	$	1,887	$	402
Costs expensed due to determination of dry hole or abandonment of project	$	8,194	$	1,197	$	—

CNX Gas’ proved gas reserves are located in the United States.

Standardized Measure of Discounted Future Net Cash Flows:

The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year ended December 31, 2009. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CNX Gas. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CNX Gas’ investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a different price and cost assumptions.

The standardized measure is intended to provide a better means for comparing the value of CNX Gas’ proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.


	December 31,
	2009			2008			2007
Future Cash Flows:
Revenues	$	7,975,195		$	8,856,817		$	9,509,665
Production costs		(3,123,532	)		(3,525,902	)		(3,004,619	)
Development costs		(995,569	)		(793,592	)		(636,436	)
Income tax expense		(1,465,075	)		(1,713,713	)		(2,259,415	)

Future Net Cash Flows		2,391,019			2,823,610			3,609,195
Discounted to present value at a 10% annual rate		(1,496,668	)		(1,605,176	)		(2,219,655	)

Total standardized measure of discounted net cash flows(a)	$	894,351		$	1,218,434		$	1,389,540

(a)	The estimated effect on the PV-10 calculation of initially applying the amendments of ASC 932 in ASU 2010-03 was $39,059.

172

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The following are the principal sources of change in the standardized measure of discounted future net cash flows during:


	December 31,
	2009			2008						2007
	Consolidated Operations			Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates
Balance at beginning of period	$	1,218,434		$	1,384,983		$	4,557		$	933,186		$	1,705
Net changes in sales prices and production costs		(333,130	)		(676,358	)		—			1,681,550			7,356
Sales net of production costs		(335,706	)		(438,382	)		—			(207,688	)		(1,122	)
Net change due to revisions in quantity estimates		189,583			(63,547	)		—			479,618			5,959
Net change due to acquisition		—			4,158			—			2,840			—
Acquisition of remaining interest in equity affiliate		—			4,557			(4,557	)		—			—
Development costs incurred during the period		181,944			378,119			—			257,935			—
Difference in previously estimated development costs compared to actual costs incurred during the period		(3,282	)		(136,742	)		—			(87,408	)		—
Changes in estimated future development costs		(380,639	)		(398,534	)		—			(254,635	)		(214	)
Net change in future income taxes		248,639			545,702			—			(754,209	)		(4,673	)
Accretion of discount and other		108,508			614,478			—			(666,206	)		(4,454	)

Total discounted cash flow at end of period	$	894,351		$	1,218,434		$	—		$	1,384,983		$	4,557

173

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Supplemental Quarterly Information (unaudited):

(Dollars in thousands)


	Three Months Ended
	March 31, 2009		June 30, 2009		September 30, 2009		December 31, 2009
Sales	$	1,164,341	$	1,003,973	$	1,032,531	$	1,158,937
Freight Revenue	$	30,916	$	27,087	$	36,130	$	54,774
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests’ Costs and Purchased Gas Costs)	$	680,095	$	649,704	$	714,627	$	751,444
Freight Expense	$	30,916	$	27,087	$	36,130	$	54,774
Net Income	$	204,971	$	118,839	$	93,286	$	150,046
Net Income Attributable to CONSOL Energy Inc Shareholders	$	195,819	$	113,339	$	87,370	$	143,189
Total Earnings per Share
Basic	$	1.08	$	0.63	$	0.48	$	0.80

Diluted	$	1.08	$	0.62	$	0.48	$	0.77

Weighted Average Shares Outstanding
Basic		180,576,479		180,644,498		180,725,194		180,823,733

Diluted		182,150,090		183,073,413		183,191,667		183,651,382


	Three Months Ended
	March 31, 2008		June 30, 2008		September 30, 2008		December 31, 2008
Sales	$	906,368	$	1,135,572	$	1,076,960	$	1,150,435
Freight Revenue	$	44,744	$	63,927	$	60,458	$	47,839
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests’ Costs and Purchased Gas Costs)	$	656,223	$	764,137	$	762,767	$	742,213
Freight Expense	$	44,744	$	63,927	$	60,458	$	47,839
Net Income	$	84,231	$	112,790	$	102,416	$	186,224
Net Income Attributable to CONSOL Energy Inc Shareholders	$	75,082	$	101,012	$	90,054	$	176,322
Total Earnings per Share
Basic	$	0.41	$	0.55	$	0.49	$	0.98

Diluted	$	0.41	$	0.54	$	0.49	$	0.97

Weighted Average Shares Outstanding
Basic		182,572,985		182,977,726		183,202,086		180,799,712

Diluted		185,192,551		185,637,248		185,591,759		182,327,963

174

Item 9.

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

Changes in Accountants.

On February 19, 2008 (Dismissal Date) CONSOL Energy dismissed PricewaterhouseCoopers LLP (PwC) as the Company’s independent registered public accounting firm. The Audit Committee of the Board of Directors of the Company recommended and approved the dismissal of PwC.

The reports of PwC on the consolidated financial statements of the Company for the year ended December 31, 2007 did not contain an adverse opinion or a disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles.

During the year ended December 31, 2007 through the Dismissal Date, there were no disagreements with PwC on any matter of accounting principles or practices, financial statement disclosures, or auditing scope or procedure, which disagreement(s), if not resolved to the satisfaction of PwC, would have caused it to make reference thereto in its reports on the financial statements of the Company for such year. During the year ended December 31, 2007, and through the Dismissal Date, there were no “reportable events” as defined under Item 304(a)(1)(v) of Regulation S-K.

Also, on February 19, 2008, the Audit Committee recommended and approved the selection of Ernst & Young LLP (“Ernst & Young), effective immediately, as the Company’s new independent registered public accounting firm.

During the year ended December 31, 2007, and through the Dismissal Date, neither the Company, nor anyone on its behalf, consulted Ernst & Young regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered with respect to the financial statements of the Company, and no written report was provided to the Company or oral advice was provided that Ernst & Young concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing or financial reporting issue; or (ii) any matter that was the subject of a disagreement (as defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions) or a “reportable event” (as described in Item 304(a)(1)(v) of Regulation S-K).

Disagreements with Accountants on Accounting and Financial Disclosures.

None.

Item 9a.

Controls and Procedures.

Disclosure controls and procedures. CONSOL Energy, under the supervision and with the participation of its management, including CONSOL Energy’s principal executive officer and principal financial officer, evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this annual report on Form 10-K. Based on that evaluation, CONSOL Energy’s principal executive officer and principal financial officer have concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by CONSOL Energy in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

175

Management’s Annual Report on Internal Control Over Financial Reporting.

CONSOL Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting. CONSOL Energy’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

CONSOL Energy’s internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of CONSOL Energy; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of CONSOL Energy’s assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of CONSOL Energy’s internal control over financial reporting as of December 31, 2009. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment and those criteria, management has concluded that CONSOL Energy maintained effective internal control over financial reporting as of December 31, 2009.

The effectiveness of CONSOL Energy’s internal control over financial reporting as of December 31, 2009 has been audited by Ernst and Young, an independent registered public accounting firm, as stated in their report set forth in the Report of Independent Registered Public Accounting Firm in Part II, Item 9a of this annual report on Form 10-K.

Changes in internal controls over financial reporting.

There were no changes that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

176

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of CONSOL Energy Inc.

We have audited CONSOL Energy Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). CONSOL Energy Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting appearing under Item 9a. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, CONSOL Energy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of CONSOL Energy Inc. (and Subsidiaries) as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, and cash flows for the years then ended and our report dated February 9, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Pittsburgh, PA

February 9, 2010

Item 9b.

Other Information.

None.

177

PART III

Item 10.

Directors and Executive Officers and Corporate Governance.

The information required by this Item is incorporated herein by reference from the information under the captions “PROPOSAL NO. 1—ELECTION OF DIRECTORS—Biography of Directors,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION—BOARD OF DIRECTORS AND ITS COMMITTEES—Corporate Governance Web Page Available Documents,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION—BOARD OF DIRECTORS AND ITS COMMITTEES—Audit Committee” and “SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the Proxy Statement for the annual meeting of shareholders to be held on May 4, 2010 (the “Proxy Statement”).

Executive Officers of CONSOL Energy

The following is a list of CONSOL Energy executive officers, their ages as of February 15, 2010 and their positions and offices held with CONSOL Energy.


Name	Age	Position
J. Brett Harvey	59	President and Chief Executive Officer
Nicholas J. DeIuliis	41	Executive Vice President and Chief Operating Officer
William J. Lyons	61	Executive Vice President and Chief Financial Officer
P. Jerome Richey	60	Executive Vice President Corporate Affairs and Chief Legal Officer
Robert P. King	57	Executive Vice President Business Advancements and Support Services
Robert F. Pusateri	59	Executive Vice President Energy Sales and Transportation Services

J. Brett Harvey has been President and Chief Executive Officer and a Director of CONSOL Energy since January 1998. He has been a Director of CNX Gas Corporation since June 30, 2005 and he became Chairman of the Board and Chief Executive Officer of CNX Gas Corporation on January 16, 2009. Mr. Harvey is a Director of Barrick Gold Corporation, the world’s largest gold producer, and Allegheny Technologies Incorporated, a specialty metals producer.

Nicholas J. DeIuliis was Senior Vice President—Strategic Planning of CONSOL Energy from November 2004 until August 2005. Prior to that time, Mr. DeIuliis served as Vice President Strategic Planning from April 2002 until November 2004, Director—Corporate Strategy from October 2001 until April 2002, Manager—Strategic Planning from January 2001 until October 2001 and Supervisor—Process Engineering from April 1999 until January 2001. He resigned from his position with CONSOL Energy as of August 8, 2005. He was a Director and President and Chief Executive Officer of CNX Gas Corporation from June 30, 2005 to January 16, 2009, when he became President and Chief Operating Officer of CNX Gas Corporation and Executive Vice President and Chief Operating Officer of CONSOL Energy.

William J. Lyons has been Chief Financial Officer of CONSOL Energy since February 2001 and Chief Financial Officer of CNX Gas Corporation since April 28, 2008. He added the title of Executive Vice President of CONSOL Energy on May 2, 2005 and of CNX Gas Corporation on January 16, 2009. From January 1995 until February 2001, Mr. Lyons held the position of Vice President—Controller for CONSOL Energy. Mr. Lyons joined CONSOL Energy in 1976. He was a Director of CNX Gas Corporation from October 17, 2005 to January 16, 2009. Mr. Lyons is a director of Calgon Carbon Corporation, a supplier of products and services for purifying water and air.

P. Jerome Richey became Executive Vice President—Corporate Affairs and Chief Legal Officer of CONSOL Energy and CNX Gas Corporation on January 16, 2009. He was General Counsel and Corporate Secretary of CONSOL Energy since March 2005, and on June 20, 2007, he added the title of Senior Vice President. Prior to joining CONSOL Energy, Mr. Richey, for more than five years, was a shareholder in the Pittsburgh office for the law firm of Buchanan Ingersoll & Rooney PC.

178

Robert P. King became Executive Vice President—Business Advancement and Support Services of CONSOL Energy and CNX Gas Corporation on January 16, 2009. Prior to that, he was Senior Vice President—Administration since February 2, 2007 and he served as Vice President—Land from August 2006 to February 2007. Prior to joining CONSOL Energy, Mr. King was Vice President of Interwest Mining Company (a subsidiary of PacifiCorp). Mr. King joined PacifiCorp in November 1990.

Robert F. Pusateri became Executive Vice President—Energy Sales and Transportation Services of CONSOL Energy and CNX Gas Corporation on January 16, 2009. Prior to that, he was named Vice President Sales of CONSOL Energy in 1996 and held that position until he was elected President of CONSOL Energy Sales Company in August 2005. He first became an officer in May 1996.

CONSOL Energy has a written Code of Business Conduct that applies to CONSOL Energy’s Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer) and others. The Code of Business Conduct is available on CONSOL Energy’s website at www.consolenergy.com. Any amendments to, or waivers from, a provision of our code of employee business conduct and ethics that applies to our principal executive officer, principal financial officer, controller, or persons performing similar functions and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting such information on our website.

By certification dated May 27, 2009, CONSOL Energy’s Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was not aware of any violation by the Company of the NYSE corporate governance listing standards. In addition, the required Sarbanes-Oxley Act, Section 302 certifications regarding the quality of our public disclosures were filed by CONSOL Energy as exhibits to this Form 10-K.

Item 11.

Executive Compensation.

The information required by this Item is incorporated by reference from the information under the captions “BOARD OF DIRECTORS AND COMPENSATION INFORMATION—DIRECTOR COMPENSATION TABLE—2009,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION—BOARD OF DIRECTORS AND ITS COMMITTEES—Compensation Committee Interlocks and Insider Participation,” “EXECUTIVE COMPENSATION AND STOCK OPTION INFORMATION” in the Proxy Statement.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this Item is incorporated by reference from the information under the caption “BENEFICIAL OWNERSHIP OF SECURITIES” and “SECURITIES AUTHORIZED FOR ISSUANCE UNDER CONSOL ENERGY EQUITY COMPENSATION PLAN” in the Proxy Statement.

Item 13.

Certain Relationships and Related Transactions and Director Independence.

The information requested by this Item is incorporated by reference from the information under the caption “Proposal No. 1—Election of Directors—Related Party Policy and Procedures” and “Determination of Director Independence” in the Proxy Statement.

Item 14.

Principal Accounting Fees and Services.

The information required by this Item is incorporated by reference from the information under the captions “ACCOUNTANTS AND AUDIT COMMITTEE—INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM,” including subsections entitled “Audit Fees,” “Audit-Related Fees,” “Tax Fees,” “All Other Fees” and “Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services” in the Proxy Statement.

179

Item 15.

Exhibit Index


(A) (1)		Financial Statements Contained in Item 8 hereof.

(A)(2)		Financial Statement Schedule—Schedule II Valuation and qualifying accounts.

3.1		Restated Certificate of Incorporation of CONSOL Energy Inc. incorporated by reference to Exhibit 3.1 to Form 8-K filed on May 8, 2006.

3.2		Amended and Restated Bylaws dated as of September 9, 2009 incorporated by reference to Exhibit 3.2 to Form 8-K filed on September 11, 2009.

4.1		Indenture, dated March 7, 2002, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.1 to Form 10-K for the transition period of July 31, 2001 to December 31, 2001 (file no. 001-14901), filed on March 29, 2002 (“Form 10-K”).

4.2		Supplemental Indenture No. 1, dated March 7, 2002, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc., and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.2 to Form 10-K for the transition period of July 31, 2001 to December 31, 2001 (file no. 001-14901), filed on March 29, 2002.

4.3		Rights Agreement, dated as of December 22, 2003, between CONSOL Energy Inc., and Equiserve Trust Company, N.A., as Rights Agent, incorporated by reference to Exhibit 4 to Form 8-K filed on December 22, 2003.

4.4		Supplemental Indenture No. 2, dated as of September 30, 2003, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc., and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.2 to Form 10-Q for the quarter ended November 30, 2003, filed on November 19, 2003.

4.5		Supplemental Indenture No. 3 dated as of April 15, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.4 to Form 10-Q for the quarter ended June 30, 2005, filed on August 3, 2005.

4.6		Supplemental Indenture No. 4 dated as of August 8, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 10.78 to Form 8-K filed on August 12, 2005.

4.7		Supplemental Indenture No. 5 dated as of October 21, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 10.21 to Amendment No. 2 to the Form S-1 for CNX Gas Corporation, filed on October 27, 2005.

4.8		Supplemental Indenture No. 6 dated as of August 2, 2006, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc., and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.8 to Form 10-Q for the quarter ended September 30, 2006, filed on November 2, 2006.

4.9		Supplemental Indenture No. 7 dated as of March 12, 2007, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc., and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.9 to Form 10-Q for the quarter ended September 31, 2007, filed on April 30, 2007.

4.10		Supplemental Indenture No. 8 dated as of May 7, 2007, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc., and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.10 to Form 10-Q for the quarter ended June 30, 2007, filed on August 1, 2007.

180


4.11		Supplemental Indenture No. 9 dated as of September 6, 2007, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 11 to Form 10-Q for the quarter ended September 30, 2007, filed on November 1, 2007.

4.12		Supplemental Indenture No. 10 dated as of November 12, 2007, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.12 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

4.13		Supplemental Indenture No. 11 dated as of June 3, 2008, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.13 to Form 10-Q for the quarter ending June 30, 2008, filed on August 5, 2008.

4.14		Supplemental Indenture No. 12 dated as of July 28, 2008, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, incorporated by reference to Exhibit 4.14 to Form 10-Q for the quarter ending June 30, 2008, filed on August 5, 2008.

10.1		Purchase and Sale Agreement, dated as of April 30, 2003, by and among CONSOL Energy Inc., CONSOL Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company, CNX Gas Company LLC, CNX Marine Terminals Inc. and CNX Funding Corporation, incorporated by reference to Exhibit 10.30 to Form 10-Q for the quarter ended June 30, 2003, filed on August 13, 2003.

10.2		Form of Indemnification Agreement for Directors and Executive Officers of CONSOL Energy Inc., incorporated by reference to Exhibit 10.6 to Form 10-Q for the quarter ended June 30, 2009, filed on August 3, 2009.

10.3		Change in Control Agreement by and between CONSOL Energy Inc. and J. Brett Harvey incorporated by reference to Exhibit 10.3 to Form 10-K for the year ended December 31, 2008, filed on February 17, 2009.

10.4		Change in Control Agreement by and between CONSOL Energy Inc. and William J. Lyons incorporated by reference to Exhibit 10.4 to Form 10-K for the year ended December 31, 2008, filed on February 17, 2009.

10.5		Change in Control Agreement by and between CONSOL Energy Inc. and Peter B. Lilly incorporated by reference to Exhibit 10.5 to Form 10-K for the year ended December 31, 2008, filed on February 17, 2009.

10.6		Change in Control Agreement by and between CONSOL Energy Inc. and P. Jerome Richey incorporated by reference to Exhibit 10.6 to Form 10-K for the year ended December 31, 2008, filed on February 17, 2009.

10.7		Change in Control Agreement by and between CONSOL Energy Inc. and Nicholas J. DeIuliis incorporated by reference to Exhibit 10.7 to Form 10-K for the year ended December 31, 2008, filed on February 17, 2009.

10.8		Change in Control Agreement by and between CONSOL Energy Inc. and Robert Pusateri incorporated by reference to Exhibit 10.8 to Form 10-K for the year ended December 31, 2008, filed on February 17, 2009.

10.9		Form of Indemnification Agreement for Directors and Executive Officers of CNX Gas Corporation incorporated by reference to Exhibit 10.7 to Form 10-Q for the quarter ended June 30, 2009, filed on August 3, 2009.

181


10.10		Chairman’s Agreement (as Amended and Restated), incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ending June 30, 2008, filed on August 5, 2008.

10.11		Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.95 to the Form 8-K filed on May 8, 2006.

10.12		Executive Officer Term Sheet with P. Jerome Richey incorporated by reference to Exhibit 10.12 to Form 10-K for the year ended December 31, 2008, filed on February 17, 2009.

10.13		Equity Incentive Plan, As Amended and Restated, effective April 28, 2009, incorporated by reference to Exhibit 10.1 to the Form 8-K filed on May 1, 2009.

10.14		Employment Agreement, dated December 2, 2008, between CONSOL Energy Inc. and J. Brett Harvey incorporated by reference to Exhibit 10.14 to Form 10-K for the year ended December 31, 2008, filed on February 17, 2009.

10.15		Master Separation Agreement, by and among CONSOL Energy Inc., CNX Gas Corporation and each of their respective subsidiaries, dated as of August 1, 2005, incorporated by reference to Exhibit 10.69 to the Form 8-K filed on August 12, 2005.

10.16		Master Cooperation and Safety Agreement, by and among CONSOL Energy Inc., CNX Gas Corporation and each of their respective subsidiaries, dated as of August 1, 2005, incorporated by reference to Exhibit 10.70 to the Form 8-K filed on August 12, 2005.

10.17		Services Agreement, by and among CONSOL Energy Inc., CNX Gas Corporation, and the subsidiaries of CNX Gas Corporation, dated as of August 1, 2005, incorporated by reference to Exhibit 10.71 to the Form 8-K filed on August 12, 2005.

10.18		Tax Sharing Agreement, by and between CONSOL Energy Inc. and CNX Gas Corporation, dated as of August 1, 2005, incorporated by reference to Exhibit 10.72 to the Form 8-K filed on August 12, 2005.

10.19		Intercompany Revolving Credit Agreement, by and between CONSOL Energy Inc. and CNX Gas Corporation, dated as of August 1, 2005, incorporated by reference to Exhibit 10.73 to the Form 8-K filed on August 12, 2005.

10.20		Master Lease dated August 1, 2005 by and between CONSOL Energy Inc. and certain of its subsidiaries and CNX Gas Company LLC, incorporated by reference to Exhibit 10.74 to the Form 8-K filed on August 12, 2005.

10.21		Originator Release by and among CONSOL Energy Inc., certain of its subsidiaries and certain banking parties dated as of August 8, 2005, incorporated by reference to Exhibit 10.77 to the Form 8-K filed on August 12, 2005.

10.22		Credit Agreement, by and among CNX Gas Corporation, the lender parties thereto, and PNC Bank National Association and Citibank, N.A., as agents, dated as of October 7, 2005, incorporated by reference to Exhibit 10.82 to the Form 8-K filed on October 13, 2005.

10.23		Non-Employee Director Option Grant Notice, as amended, incorporated by reference to Exhibit 10.84 to the Form 8-K filed on October 24, 2005.

10.24		Agreement, dated October 2, 2002 between CONSOL Energy Inc. and Peter B. Lilly, incorporated by reference to Exhibit 10.89 to Form 10-K for the year ended December 31, 2005 (file no. 001-14901). filed on March 15, 2006.

10.25		Form Of Non-Qualified Stock Option Award Agreement For Employees, incorporated by reference to Exhibit 10.26 to the Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.

10.26		Form of Non-qualified Stock Option Award Agreement for Employees (February 17, 2009 and after) incorporated by reference to Exhibit 10.28 to Form S-4 filed on June 26, 2009.

182


10.27		Form Of Restricted Stock Unit Award Agreement For CONSOL Employees, incorporated by reference to Exhibit 10.28 to the Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.

10.28		Form of Restricted Stock Unit Award for Employees (February 17, 2009 and after) incorporated by reference to Exhibit 10.31 to Amendment No. 1 to Form S-4 filed on June 26, 2009.

10.29		Form Of Restricted Stock Unit Award Agreement For Directors, incorporated by reference to Exhibit 10.30 to the Registration Statement on Form S-4 (file no. 333-149442) filed on February 28, 2008.

10.30		Amended and Restated Retirement Restoration Plan of CONSOL Energy Inc. incorporated reference to Exhibit 10.30 to Form 10-K for the year ended December 31, 2008, filed February 17, 2009.

10.31		First Amendment to Purchase and Sale Agreement dated as of April 30, 2007, entered into among CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals Inc., each an “Originator” and CNX Funding Corporation, incorporated by reference to Exhibit 10.31 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.32		Second Amendment to Purchase and Sale Agreement dated as of November 16, 2007, entered into among CONSOL Energy Inc. (“CONSOL Energy”), CONSOL Energy Sales Company, CONSOL of Kentucky Inc., Consol Pennsylvania Coal Company LLC, Consolidation Coal Company, Island Creek Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company and CNX Marine Terminals Inc. (each an “Existing Originator”) and collectively the “Existing Originators”), Fola Coal Company, LLC., Little Eagle Coal Company, LLC., Mon River Towing, Inc., Terry Eagle Coal Company, LLC., Tri-River Fleeting Harbor Service, Inc., and Twin Rivers Towing Company (each, a “New Originator” and collectively the “New Originators”; the Existing Originators and the New Originators, each an “Originator” and collectively, the “Originators”), Windsor Coal Company (the “Released Originator”) and CNX Funding Corporation, incorporated by reference to Exhibit 10.32 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.33		Amended and Restated Receivable Purchase Agreement, dated as of April 30, 2007, by and among CNX Funding Corporation, CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company, Consolidation Coal Company, Island Creek Coal Company, Windsor Coal Company, McElroy Coal Company, Keystone Coal Mining Corporation, Eighty-Four Mining Company, CNX Marine Terminals Inc., Market Street Funding LLC, Liberty Street Funding LLC, PNC Bank, National Association, and the Bank of Nova Scotia, incorporated by reference to Exhibit 10.33 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.34		First Amendment to Amended and Restated Receivables Purchase Agreement (this “Amendment”), dated as of May 9, 2007, entered into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the Conduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LC Participants listed on the signature pages of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.34 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.35		Second Amendment to Amended and Restated Receivables Purchase Agreement (this “Amendment”), dated as of July 27, 2007, entered into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer (in such capacity, the “Servicer”), the Conduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LC Participants listed on the signature pages of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.35 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

183


10.36		Third Amendment to Amended and Restated Receivables Purchase Agreement (this “Amendment”), dated as of November 16, 2007, entered into among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various new sub-servicers listed on the signature pages of the Amendment, the Conduit Purchasers listed on the signature pages of the Amendment, the Purchaser Agents listed on the signature pages of the Amendment, the LC Participants listed on the signature pages hereto and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.36 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.37		Amended and Restated Credit Agreement, dated as of June 27, 2007 by and among CONSOL Energy Inc., the Guarantors (as defined therein), the Lenders (as defined therein), The Bank of Nova Scotia, Bank of America, N.A., and Union Bank of California, N.A., each in its capacity as a co-syndication agent, and PNC Bank, National Association and Citicorp North America, Inc., in their capacity as co- administrative agents for the Lenders under the Agreement, incorporated by reference to Exhibit 10.1 to Form 8-K filed on July 3, 2007.

10.38		Amended and Restated Collateral Trust Agreement (“Agreement”) dated as of June 27, 2007, by and among CONSOL Energy Inc., (the “Borrower”), certain subsidiaries of the Borrower which have joined the Agreement, Wilmington Trust Company, not in its individual capacity but solely as corporate trustee, and David A. Vanaskey, not in his individual capacity but solely as individual trustee, as trustees for the Secured Parties, incorporated by reference to Exhibit 10.38 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.39		Continuing Agreement of Guaranty and Suretyship (“Guaranty”), dated as of June 30, 2004, jointly and severally given by each of the undersigned thereto and each of the other Persons which become Guarantors thereunder from time to time (each a “Guarantor” and collectively the “Guarantors”) in favor of PNC Bank, National Association, as paying agent for the Lenders (the “Paying Agent”), in connection with that certain Credit Agreement as defined therein, incorporated by reference to Exhibit 10.39 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.40		Amended and Restated Pledge Agreement, dated as of June 27, 2007 made and entered into by each of the pledgors listed on the signature pages thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption, or otherwise, and Wilmington Trust Company, not in its individual capacity but solely as collateral trustee for the equal and ratable benefit of the Secured Parties (as defined therein) pursuant to the Collateral Trust Agreement, incorporated by reference to Exhibit 10.40 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.41		Amended and Restated Security Agreement dated as of June 27, 2007, entered into by and between CONSOL Energy Inc., and each of the other parties listed on the signature pages thereto and each of the other persons and entities that become bound thereby from time to time by joinder, assumption or otherwise, and Wilmington Trust Company, not in its individual capacity but solely as the collateral trustee for the equal and ratable benefit of the Secured Parties pursuant to the Collateral Trust Agreement, incorporated by reference to Exhibit 10.41 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.42		2008 STIC Plan, incorporated by reference to Exhibit 10.5 to Form 10-Q for the quarter ending March 31, 2008, filed on April 30, 2008.

10.43		Amended and Restated Long-Term Incentive Program (2007-09), incorporated by reference to Exhibit 10.43 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.44		Time Sharing Agreement, dated as of May 1, 2007, by and between CONSOL Energy Inc. and J. Brett Harvey, incorporated by reference to Exhibit 10.1 to Form 8-K filed on May 7, 2007.

10.45		Letter Agreement, dated August 24, 2007, by and between CONSOL Energy Inc. and Nicholas J. DeIuliis, incorporated by reference to Exhibit 10.1 to Form 8-K filed on August 24, 2007.

184


10.46		Agreement, dated September 12, 2007, by and between CONSOL Energy Inc. and Bart Hyita, regarding CONSOL Energy Inc. Supplemental Retirement Plan, incorporated by reference to Exhibit 10.112 of Form 10-Q for the quarter ended September 30, 2007, filed on November 1, 2007.

10.47		Summary of Non-Employee Director Compensation, incorporated by reference to Exhibit 10.111 of Form 10-Q for the quarter ended September 30, 2007, filed on November 1, 2007.

10.48		Directors’ Deferred Fee Plan (2004 Plan) (Amended and Restated on December 4, 2007), incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ending March 31, 2008, filed on April 30, 2008.

10.49		Hypothetical Investment Election Form Relating to Directors’ Deferred Fee Plan, incorporated by reference to Exhibit 10.50 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.50		Directors Deferred Compensation Plan (1999 Plan), incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ending March 31, 2008, filed on April 30, 2008.

10.51		Hypothetical Investment Election Form Relating to Directors’ Deferred Compensation Plan, incorporated by reference to Exhibit 10.53 to Form 10-K for the year ended December 31, 2007 (file no. 001-14901), filed on February 19, 2008.

10.52		Amended and Restated Supplemental Retirement Plan of CONSOL Energy Inc. effective January 1, 2007, as amended and restated on September 8, 2009, incorporated by reference to Exhibit 10.1 to Form 8-K filed on September 11, 2009.

10.53		Trust Agreement (Amended and Restated on March 20, 2008) (1999 Directors Deferred Compensation Plan), incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ending March 31, 2008, filed on April 30, 2008.

10.54		Trust Agreement (Amended and Restated on March 20, 2008) (2004 Directors Deferred Fee Plan), incorporated by reference to Exhibit 10.4 to Form 10-Q for the quarter ending March 31, 2008, filed on April 30, 2008.

10.55		Long-Term Incentive Program (2008 – 2010), incorporated by reference to Exhibit 10.6 to Form 10-Q for the quarter ending March 31, 2008, filed on April 30, 2008.

10.56		Executive Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K filed on May 1, 2008.

10.57		Amendment No. 1 To The Master Cooperation And Safety Agreement, incorporated by reference to Exhibit 10.1 to Form 8-K filed on June 2, 2008.

10.58		First Amendment to Amended and Restated Credit Agreement, incorporated by reference to Exhibit 10.59 to Form 10-K for the year ended December 31, 2008 filed on February 17, 2009.

10.59		Letter Agreement by and between Peter B. Lilly and CONSOL Energy Inc., effective March 10, 2009, incorporated by reference to Exhibit 10.1 to the Form 8-K filed on March 10, 2009.

10.60		Long-Term Incentive Program (2009-2011), incorporated by reference to Exhibit 10.1 to Form 10-Q for the quarter ending March 31, 2009, filed on April 27, 2009.

10.61		Election Form to Exchange CNX Gas Performance Share Units into CONSOL Energy Inc. Restricted Stock Units (Private Placement), incorporated by reference to Exhibit 10.2 to Form 10-Q for the quarter ending March 31, 2009, filed on April 27, 2009.

10.62		Form CONSOL Energy Inc. Restricted Stock Unit Award Agreement for Individuals Exchanging CNX Gas Performance Share Units into CONSOL Energy Inc. Restricted Stock Units (Private Placement), incorporated by reference to Exhibit 10.3 to Form 10-Q for the quarter ending March 31, 2009, filed on April 27, 2009.

185


10.63		Form of Election and Restricted Stock Unit Award Agreement (Exchange Offer), incorporated by reference to Exhibit 99.1 to Form S-4 Filed on June 26, 2009.

12		Computation of Ratio of Earnings to Fixed Charges.

14.1		Code of Employee Business Conduct, incorporated by reference to Exhibit 14.1 to Form 8-K filed on December 5, 2008.

21		Subsidiaries of CONSOL Energy Inc.

23.1		Consent of Ernst & Young LLP

23.2		Consent of PricewaterhouseCoopers LLP.

23.3		Consent of Netherland Sewell & Associates, Inc.

23.4		Consent of Schlumberger Data and Consulting Services

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

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

99		Engineers’ Audit Letter

101		Interactive Data File (Form 10-K for the quarterly period ended December 31, 2009 furnished in XBRL).

Supplemental Information

No annual report or proxy material has been sent to shareholders of CONSOL Energy at the time of filing of this Form 10-K. An annual report will be sent to shareholders subsequent to the filing of this Form 10-K. Said annual report will be forwarded to the commission when the same are sent to shareholders of CONSOL Energy.

In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.

186

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, as of the 9th day of February, 2010.


CONSOL ENERGY INC.

By:		/s/ J. BRETT HARVEY
		J. Brett Harvey,
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 9th day of February, 2010, by the following persons on behalf of the registrant in the capacities indicated:


Signature		Title

/s/ JOHN L. WHITMIRE John L. Whitmire		Chairman of the Board

/s/ J. BRETT HARVEY J. Brett Harvey		President and Chief Executive Officer and Director (Principal Executive Officer)

/s/ WILLIAM J. LYONS William J. Lyons		Chief Financial Officer and Executive Vice President (Principal Financial and Accounting Officer)

/s/ JAMES E. ALTMEYER, SR. James E. Altmeyer, Sr.		Director

/s/ WILLIAM E. DAVIS William E. Davis		Director

/s/ WILLIAM P. POWELL William P. Powell		Director

/s/ JOSEPH T. WILLIAMS Joseph T. Williams		Director

/s/ RAJ K. GUPTA Raj K. Gupta		Director

/s/ DAVID C. HARDESTY, JR. David C. Hardesty, Jr.		Director

/s/ JOHN T. MILLS John T. Mills		Director

/s/ PHILIP W. BAXTER Philip W. Baxter		Director

187

SCHEDULE II

CONSOL ENERGY INC. AND SUBSIDIARIES

Valuation and Qualifying Accounts

(Dollars in thousands)


	Balance at Beginning of Period		Additions		Deductions			Balance at End of Period
	Balance at Beginning of Period		Charged to Expense		Release of Valuation Allowance			Balance at End of Period
Year Ended December 31, 2009
State operating loss carry-forwards	$	34,714	$	2,640	$	(302	)	$	37,052
Deferred deductible temporary differences		26,184		949		(2,562	)		24,571

Total	$	60,898	$	3,589	$	(2,864	)	$	61,623

Year Ended December 31, 2008
State operating loss carry-forwards	$	36,785	$	—	$	(2,071	)	$	34,714
Deferred deductible temporary differences		23,123		3,061		—			26,184

Total	$	59,908	$	3,061	$	(2,071	)	$	60,898

Year Ended December 31, 2007
State operating loss carry-forwards	$	38,237	$	—	$	(1,452	)	$	36,785
Deferred deductible temporary differences		27,847		—		(4,724	)		23,123

Total	$	66,084	$	—	$	(6,176	)	$	59,908

188