Edgar Filing: CONSOL Energy Inc

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, 2010;

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

For the transition period from to

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 of this chapter) 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, 2010, 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 $7,615,554,265.

The number of shares outstanding of the registrant’s common stock as of January 28, 2011 is 226,236,682 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of CONSOL Energy’s Proxy Statement for the Annual Meeting of Shareholders to be held on May 4, 2011,

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		41

Item 1B.	Unresolved Staff Comments		57

Item 2.	Properties		57

Item 3.	Legal Proceedings		58

Item 4.	Submission of Matters to a Vote of Security Holders		58

PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities		59

Item 6.	Selected Financial Data		60

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		65

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		114

Item 8.	Financial Statements and Supplementary Data		116

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		188

Item 9A.	Controls and Procedures		188

Item 9B.	Other Information		191

PART III

Item 10.	Directors and Executive Officers of the Registrant		194

Item 11.	Executive Compensation		195

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		195

Item 13.	Certain Relationships and Related Transactions and Director Independence		195

Item 14.	Principal Accounting Fees and Services		196

PART IV

Item 15.	Exhibits and Financial Statement Schedules		196

SIGNATURES			206

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:

•

deterioration in economic conditions in any of the industries 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;

•

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

•

our reliance on major customers;

•

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

•

the disruption of rail, barge, gathering, processing and transportation facilities and other systems that deliver our coal and gas to market;

•

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 ability to negotiate a new agreement with the United Mine Workers’ of America and 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 emissions;

•

the impact of potential, as well as any adopted regulations relating to greenhouse gas emissions on the demand for coal and natural gas, as well as the impact of any adopted regulations on our coal mining operations due to the venting of coalbed methane which occurs during mining;

•

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

•

the risks inherent in coal and gas operations being subject to unexpected disruptions, including geological conditions, equipment failure, timing of completion of significant construction or repair of equipment, fires, explosions, accidents and weather conditions which could impact financial results;

•

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

•

decreases in the availability of, or increases in, the price of commodities and services used in our mining and gas operations, as well as our exposure under “take or pay” contracts we entered into with well service providers to obtain services of which if not used could impact our cost of production;

•

obtaining and renewing governmental permits and approvals for our coal and gas operations;

•

the effects of government regulation on the discharge into the water or air, and the disposal and clean-up of, hazardous substances and wastes generated during our coal and gas operations;

•

the effects of stringent federal and state employee health and safety regulations, including the ability of regulators to shut down a mine or well;

•

the potential for liabilities arising from environmental contamination or alleged environmental contamination in connection with our past or current coal and gas operations;

•

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

•

uncertainties in estimating our economically recoverable coal and gas reserves;

•

costs associated with perfecting title for coal or gas rights on some of our properties;

•

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

•

the impacts of various asbestos litigation claims;

•

increased exposure to employee related long-term liabilities;

•

increased exposure to multi-employer pension plan 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 exceeding total service and interest cost in a plan year;

•

acquisitions that we recently have completed 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 and divestitures we anticipate may not occur or produce anticipated proceeds;

•

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

•

increased exposure on our financial performance due to the degree we are leveraged;

•

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

•

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

•

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

•

other factors discussed in this 2010 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, 2010, we produced high-British thermal unit (Btu) bituminous coal from 13 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 produce 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 62 million tons of coal in 2010 accounted for approximately 6% of the total tons produced in the United States and almost 14% of the total tons produced east of the Mississippi River during 2010. 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 largest amount of recoverable coal reserves 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.

CONSOL Energy is a leader in developing unconventional gas resources. CONSOL Energy is an industry leader in the development of coalbed methane production in the Eastern United States and is also a leader in the development of the Marcellus shale. CONSOL Energy holds considerable positions in other unconventional plays including: Chattanooga, New Albany, Huron and Utica shales. We also hold a large position in conventional Appalachian assets from the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion Acquisition). 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 127.9 billion cubic feet of gas in the year ended December 31, 2010;

•

At December 31, 2010, we had 12,587 net producing wells; and

•

We controlled approximately 3.7 trillion cubic feet of net proved reserves at December 31, 2010, of which 48% 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

CONSOL Energy has two principal business divisions: Coal and Gas. The principal activities of the Coal Division are mining, preparation and marketing of steam coal, sold primarily to the electric power generation industry, and metallurgical coal, sold to metal and coke producers. The Coal Division includes four reportable segments. These reportable segments are Steam, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the year ended December 31, 2010, the Steam coal aggregated segment includes the following mines: Bailey, Blacksville #2, Buchanan, Emery, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. For the year ended December 31, 2010, the Low Volatile Metallurgical coal aggregated segment includes the Buchanan mine. For the year ended December 31, 2010, the High Volatile Metallurgical coal aggregated segment includes: Bailey, Blacksville #2, Enlow Fork, Fola Complex and Emery coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, as well as various other activities assigned to the coal division but not allocated to each individual mine. The principal activity of the Gas division is to produce pipeline quality methane gas for sale primarily to gas wholesalers. The Gas Division includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus, Conventional and Other Gas. The Other Gas segment includes our purchased gas activities as well as various other activities assigned to the gas division but not allocated to each individual well type. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities. Financial Information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years ended December 31, 2010, 2009 and 2008 is included in Note 25—Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K and incorporated herein.

Coal Operations

Mining Complexes

During the year ended December 31, 2010, CONSOL Energy had 13 active mining complexes, including two 49% equity affiliates, 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, 2010 and 2009


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) 12/31/2009
Mine/Reserve	Location		Reserve Class		Coal Seam		Average Seam Thickness (feet)		Typical		Range		Owned (%)			Leased (%)			Tons in Millions 12/31/2010		Recoverable Reserves (tons in Millions) 12/31/2009
ASSIGNED—OPERATING
Steam Reserves
Enlow Fork(4)		Enon, PA		Assigned		Pittsburgh		5.4		12,940		12,860 – 13,060		100	%		—	%		38.7		48.9
				Accessible		Pittsburgh		5.3		12,900		12,830 – 13,000		79	%		21	%		197.9		197.9
Bailey(4)		Enon, PA		Assigned		Pittsburgh		5.7		12,950		12,860 – 13,060		44	%		56	%		112.3		74.5
				Accessible		Pittsburgh		5.6		12,900		12,830 – 13,000		90	%		10	%		334.3		382.8
McElroy		Glen Easton, WV		Assigned		Pittsburgh		5.7		12,570		12,450 – 12,650		100	%		—	%		7.4		195.0
				Accessible		Pittsburgh		5.8		12,530		12,410 – 12,610		94	%		6	%		153.1		153.0
Shoemaker		Moundsville, WV		Assigned		Pittsburgh		5.6		12,200		11,700 – 12,300		100	%		—	%		44.5		48.4
				Accessible		Pittsburgh		5.6		12,250		11,990 – 12,390		100	%		—	%		27.8		27.8
Loveridge		Metz, WV		Assigned		Pittsburgh		7.5		13,050		12,850 – 13,150		81	%		19	%		32.0		37.9
				Accessible		Pittsburgh		7.6		13,000		12,820 – 13,100		95	%		5	%		13.6		13.6
Robinson Run		Shinnston, WV		Assigned		Pittsburgh		7.4		12,940		12,600 – 13,300		87	%		13	%		52.7		58.2
				Accessible		Pittsburgh		6.8		12,940		12,600 – 13,300		55	%		45	%		156.7		156.7
Blacksville #2(4)		Wana, WV		Assigned		Pittsburgh		6.7		13,050		12,800 – 13,150		85	%		15	%		24.7		29.1
				Accessible		Pittsburgh		6.9		13,000		12,800 – 13,100		99	%		1	%		16.5		16.5
Harrison Resources(3)		Cadiz, OH		Assigned		Multiple		4.5		11,570		11,350 – 11,850		100	%		—	%		7.1		9.2
Amvest-Fola Complex(4)		Bickmore, WV		Assigned		Multiple		3.6		12,380		12,250 – 12,550		92	%		8	%		53.3		101.7
Miller Creek Complex		Delbarton, WV		Assigned		Multiple		8.0		12,000		11,600 – 12,650		15	%		85	%		9.0		10.0
Emery(4)		Emery Co., UT		Assigned		Ferron I		7.5		12,260		12,000 – 13,000		71	%		29	%		17.9		16.9
Metallurgical Reserves
Buchanan		Mavisdale, VA		Assigned		Pocahontas 3		5.7		13,980		13,700 – 14,200		20	%		80	%		63.7		68.4
				Accessible		Pocahontas 3		6.0		13,930		13,650 – 14,150		10	%		90	%		37.0		37.0
Western Allegheny—Knob Creek(3)		Young Township, PA		Assigned		Upper Kittaning		3.2		13,050		13,000 – 13,100		100	%		—	%		2.4		—

Total Assigned Operating and Accessible																				1,402.6		1,683.5

(1)

The heat value shown for assigned reserves is based on the quality of coal mined and processed during the year ended December 31, 2010. 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 and Western Allegheny—Knob Creek are both equity affiliates in which CONSOL Energy owns a 49% interest. Reserves reported equal CONSOL Energy’s 49% proportionate interest in Harrison Resources’ and Western Allegheny—Knob Creek’s reserves.

(4)	A portion of these reserves contain metallurgical qualities and are currently being sold on the metallurgical market.

Excluded from the table above are approximately 233.6 million tons of reserves at December 31, 2010 that are assigned to projects that have not produced coal in 2010. These assigned reserves are in the Northern Appalachia (northern West Virginia and Pennsylvania), Central Appalachia (Virginia and eastern Kentucky) and Illinois Basin (Illinois) regions. These reserves are approximately 61% owned and 39% 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 it 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, 2010, CONSOL Energy had an estimated 4.4 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 that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by 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 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 the electric power generation industry.

CONSOL Energy’s reserves are located in northern Appalachia (63%), central Appalachia (13%), the mid-western United States (18%), the western United States (4%), and in western Canada (2%) at December 31, 2010.

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

CONSOL Energy UNASSIGNED Recoverable Coal Reserves as of December 31, 2010 and 2009


			Recoverable Reserves(2)								Recoverable Reserves (tons in Millions) 12/31/2009
Coal Producing Region	As Received Heat Value(1) (Btu/lb)		Owned (%)			Leased (%)			Tons in Millions 12/31/2010
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)		11,400 – 13,500		73	%		27	%		1,412.2		1,239.7
Central Appalachia (Virginia, Southern West Virginia, Eastern Kentucky)		11,900 – 14,200		45	%		55	%		327.7		301.4
Illinois Basin (Illinois, Western Kentucky, Indiana)		11,500 – 11,900		43	%		57	%		777.9		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				61	%		39	%		2,764.8		2,568.7

(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, 2010 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, 2010


	£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		—			—			—			—			—			164.7			—			—			—			164.7			3.7	%
Steam:
High Vol A Bituminous		—			—			—			—			—			111.3			62.2			119.6			2,279.2			2,572.3			58.4	%
Low Vol Bituminous		—			—			—			—			—			33.6			—			—			—			33.6			0.8	%

Region Total		—			—			—			—			—			309.6			62.2			119.6			2,279.2			2,770.6			62.9	%
Central Appalachia:
Metallurgical:
High Vol A Bituminous		—			3.0			53.6			—			—			2.8			—			—			1.3			60.7			1.4	%
Med Vol Bituminous		—			—			110.0			—			—			2.9			—			—			—			112.9			2.6	%
Low Vol Bituminous		—			—			119.8			—			—			26.2			—			—			—			146.0			3.3	%
Steam:
High Vol A Bituminous		26.3			71.8			4.5			32.8			26.3			62.2			—			1.1			3.6			228.6			5.2	%

Region Total		26.3			74.8			287.9			32.8			26.3			94.1			—			1.1			4.9			548.2			12.5	%
Midwest-Illinois Basin:
Steam:
High Vol B Bituminous		—			—			—			—			79.3			—			—			457.9			—			537.2			12.2	%
High Vol C Bituminous		—			—			—			—			159.5			—			108.3			—			—			267.8			6.1	%

Region Total		—			—			—			—			238.8			—			108.3			457.9			—			805.0			18.3	%
Northern Powder River Basin:
Steam:
Sub Bituminous B		—			—			169.1			—			—			—			—			—			—			169.1			3.8	%

Region Total		—			—			169.1			—			—			—			—			—			—			169.1			3.8	%
Utah-Emery Field:
Steam:
High Vol B Bituminous		—			17.9			—			—			12.3			—			—			—			—			30.2			0.7	%

Region Total		—			17.9			—			—			12.3			—			—			—			—			30.2			0.7	%
Western Canada:
Metallurgical:
Med Vol Bituminous		30.2			47.7			—			—			—			—			—			—			—			77.9			1.8	%

Region Total		30.2			47.7			—			—			—			—			—			—			—			77.9			1.8	%

Total Company		56.5			140.4			457.0			32.8			277.4			403.7			170.5			578.6			2,284.1			4,401.0			100.0	%

Percent of Total		1.3	%		3.2	%		10.4	%		0.7	%		6.3	%		9.2	%		3.9	%		13.1	%		51.9	%		100.0	%

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.

CONSOL Energy Proven and Probable Recoverable Coal Reserves

By Product (In Millions of Tons) As of December 31, 2010


	£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		—			3.0			53.6			—			—			167.5			—			—			1.3			225.4			5.1	%
Med Vol Bituminous		30.2			47.7			110.0			—			—			2.9			—			—			—			190.8			4.3	%
Low Vol Bituminous		—			—			119.8			—			—			26.2			—			—			—			146.0			3.3	%

Total Metallurgical		30.2			50.7			283.4			—			—			196.6			—			—			1.3			562.2			12.7	%
Steam:
High Vol A Bituminous		26.3			71.8			4.5			32.8			26.3			173.5			62.2			120.7			2,282.8			2,800.9			63.6	%
High Vol B Bituminous		—			17.9			—			—			91.6			—			—			457.9			—			567.4			12.9	%
High Vol C Bituminous		—			—			—			—			159.5			—			108.3			—			—			267.8			6.1	%
Low Vol Bituminous		—			—			—			—			—			33.6			—			—			—			33.6			0.9	%
Sub Bituminous B		—			—			169.1			—			—			—			—			—			—			169.1			3.8	%

Total Steam		26.3			89.7			173.6			32.8			277.4			207.1			170.5			578.6			2,282.8			3,838.8			87.3	%

Total		56.5			140.4			457.0			32.8			277.4			403.7			170.5			578.6			2,284.1			4,401.0			100.0	%

Percent of Total		1.3	%		3.2	%		10.4	%		0.7	%		6.3	%		9.2	%		3.9	%		13.1	%		51.9	%		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 former national 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 this former sulfur dioxide standard may not meet an emission standard for a different pollutant such as mercury, and may not even meet newer sulfur emission standards for all power plants. Clean air regulations that further restrict sulfur dioxide emissions will likely significantly reduce 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, 2010, approximately 0.7 billion tons, or 15%, of our coal reserves met that standard as a compliance coal. It is likely that, within several years, no coal will be “compliant” because federal regulations will require emissions-control technology to be used regardless of the coal’s sulfur content. In many cases, our customers have responded to ever-tightening emissions 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, those 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) was required to promulgate 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 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 trillion Btu) 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 more easily captured by scrubbers installed for sulfur control) than sub-bituminous coal, including coals produced in the Powder River Basin. Both high rank and low rank coals are also amenable to other methods of controlling mercury emissions, such as by powder activated carbon injection. The EPA’s proposed Clean Air Mercury Rule was vacated by a federal court ruling. The EPA is currently developing new regulations to control multiple hazardous air pollutants, including mercury, from coal-fired plants, the so-called MACT Rule, which is expected to be finalized in 2014. Some states have already adopted a control program for mercury emissions from coal-fired power plants.

Production

In the year ended December 31, 2010, 94% of CONSOL Energy’s production came from underground mines and 6% 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, 2010, 91% 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, 2010, 2009 and 2008, the location of each mine, the type of mine, the type of equipment used at each mine, method of transportation 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
Mine	Location		Mine Type	Mining Equipment	Transportation	2010		2009		2008		Year Established or Acquired
Steam
McElroy		Glen Easton, WV	U	LW/CM	CB B		10.1		9.9		9.6		1968
Bailey		Enon, PA	U	LW/CM	R R/B		9.8		10.4		10.0		1984
Enlow Fork—Steam		Enon, PA	U	LW/CM	R R/B		9.1		11.1		11.1		1990
Loveridge		Metz, WV	U	LW/CM	R T		5.9		6.0		5.2		1956
Robinson Run		Shinnston, WV	U	LW/CM	R CB		5.5		5.6		5.6		1966
Blacksville #2(1)		Wana, WV	U	LW/CM	R R/B T		4.5		3.8		5.6		1970
Shoemaker(2)		Moundsville, WV	U	LW/CM	B		3.9		0.4		1.1		1966
Miller Creek Complex(3)		Delbarton, WV	U/S	CM /S/L	R T		3.0		3.2		3.1		2004
AMVEST—Fola Complex(1)(3)		Bickmore, WV	U/S	A /S/L CM	R T		1.9		3.0		3.9		2007
Emery		Emery Co., UT	U	CM	T		1.0		1.2		1.1		1945
Harrison Resources(3)(4)		Cadiz, OH	S	S/L	R T		0.5		0.4		0.2		2007
Buchanan—Steam(1)(5)		Mavisdale, VA	U	LW/CM	R		0.2		0.7		0.5		1983
Jones Fork Complex(1)(3)(6)		Mousie, KY	U/S	CM / S/L	R T		0.1		1.1		2.5		1992
Mine 84(1)		Eighty Four, PA	U	LW/CM	R R/B T		—		0.5		1.8		1998
AMVEST—Terry Eagle Complex		Jodie, WV	U/S	CM /A /S/L	R T		—		—		0.4		2007
High Volatile Metallurgical
Bailey—Met		Enon, PA	U	LW/CM	R R/B		1.2		—		—		1984
Enlow Fork—Met		Enon, PA	U	LW/CM	R R/B		1.1		—		—		1990
Western Allegheny—Knob Creek(4)		Young Township, PA	U	CM	R T		0.1		—		—		2010
Low Volatile Metallurgical
Buchanan(1)(5)		Mavisdale, VA	U	LW/CM	R		4.5		2.1		3.0		1983
Amonate Complex(1)		Amonate, VA	U/S	CM / S/L	R T		—		—		0.4		1925

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(s) presented 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 Resources, Miller Creek Complex, Amvest Fola, Jones Fork and Western Allegheny—Knob Creek include facilities operated by independent mining contractors.

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

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

(6)	– Complex was sold in March 2010.

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


	Years Ended December 31,
	2010		2009		2008
Average Sales Price Per Ton Produced—Steam Coal	$	53.48	$	56.57	$	45.01
Average Sales Price Per Ton Produced—High Volatile Met Coal	$	75.27	$	—	$	—
Average Sales Price Per Ton Produced—Low Volatile Met Coal	$	151.31	$	104.16	$	116.94
Average Sales Price Per Ton Produced—Total Company	$	61.35	$	58.28	$	48.77

Construction of a new slope and overland belt at the Bailey Mine in Pennsylvania was completed in April 2010. Overland belt projects are expected to enhance safety, improve productivity, increase production and reduce costs. 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 overland belts because older underground belt areas will be sealed. Construction of a new slope and overland belt at the Enlow Fork Mine in Pennsylvania began in 2010 and is expected to be completed by the end of December 2013.

A project to upgrade the Bailey Preparation Plant began in September 2010 and is expected to be completed by June 2011. This efficiency upgrade will include adding 10 screen bowls to the plant resulting in higher yield and cost savings.

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 was completed in December 2010 and final commissioning of the RO system will be complete by the end of March 2011.

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, 2010, 2009 and 2008.


Year	Total Royalty Tonnage (in thousands)		Total Coal Acreage Leased		Total Royalty Income (in thousands)
2010		8,606		226,524	$	14,073
2009		11,403		232,181	$	16,448
2008		11,757		218,273	$	18,775

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 2009, the latest year for which statistics are available.

MAJOR U.S. UNDERGROUND COAL MINES—2009

In millions of tons


Mine Name	Operating Company	Production
Enlow Fork	CONSOL Energy		11.1
Bailey	CONSOL Energy		10.4
McElroy	CONSOL Energy		9.9
Twenty Mile	Peabody Energy Subsidiary		7.7
Cumberland	Pennsylvania Services (Alpha)		6.8
Powhatan No. 6	The Ohio Valley Coal Company (Murray)		6.7
SUFCO	Arch Coal, Inc.		6.6
San Juan	BHP Billiton		6.5
Warrior	Warrior Coal, LLC (Alliance)		6.2
Century	American Energy Corp. (Murray)		6.0
Loveridge	CONSOL Energy		6.0
Mach #1	Mach Mining, LLC		5.9
Elk Creek	Oxbow Mining, LLC		5.7
Emerald	Emerald Resources (Alpha)		5.6
Robinson Run	CONSOL Energy		5.6
Dotiki	Webster County Coal, LLC (Alliance)		4.2
West Elk	Arch Coal, Inc.		4.0
Elk Creek	Hopkins Country Coal, LLC (Alliance)		4.0
New Era	American Energy Corp. (Murray)		3.9
Blacksville 2	CONSOL Energy		3.8

Source: National Mining Association, EIA

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 Charlotte, Philadelphia and Pittsburgh. In addition, we sell coal through agents and to brokers and unaffiliated trading companies. In 2010, we sold 63.9 million tons of coal, including our portion of equity affiliates. Of these sales, 79% were sold in domestic markets. Our direct sales to domestic electricity generators represented 70% of our total tons sold in 2010. We had approximately 85 customers in 2010. During 2010, 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.

We announced in 2010 an exclusive agreement with Xcoal, who opened offices in Seoul, Beijing, Singapore, Tokyo and Delhi. This agreement provides CONSOL Energy’s Northern Appalachia and Buchanan coals increased access to these growing Asian markets.

Coal Contracts

We sell coal to an established customer base through opportunities as a result of strong business relationships, or through a formalized bidding process. Contract volumes range from a single shipment to multi-year agreements for millions of tons of coal. The average contract term is between one to three years. However, several multi-year agreements have terms ranging from five to twenty years. As a normal course of business, efforts are made 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. For the year ended December 31, 2010, over 89% of all the coal we produced was sold under contracts with terms of one year or more.

The following table sets forth, as of January 8, 2011, the total tons of coal CONSOL Energy is committed to deliver from 2011 through 2015.


	Tons/Dollars of Coal to be Delivered (Tons in millions of nominal tons)
	2011		2012		2013		2014		2015
Committed tons without pricing:
Steam		—		20.5		20.2		21.7		20.0
High Volatile Met		0.7		0.2		—		—		—
Low Volatile Met		1.5		2.6		2.3		0.4		—

Total Company		2.2		23.3		22.5		22.1		20.0

Committed tons with firm pricing:
Steam		52.6		22.3		11.5		4.8		2.2
High Volatile Met		0.7		0.4		0.3		0.2		0.2
Low Volatile Met		2.2		0.3		0.2		0.1		0.1

Total Company		55.5		23.0		12.0		5.1		2.5

Average realized price:
Steam	$	57.68	$	61.49	$	58.98	$	49.14	$	50.09
High Volatile Met	$	77.20	$	77.71	$	93.43	$	108.21	$	110.92
Low Volatile Met	$	160.70	$	90.21	$	81.82	$	80.00	$	80.00

Total Company	$	62.03	$	62.09	$	60.08	$	51.76	$	55.48

*Committed tons priced with collars:**
Steam
Tons		—		5.8		6.9		6.9		8.9
Average ceiling	$	—	$	51.60	$	56.88	$	60.25	$	59.64
Average floor	$	—	$	43.07	$	47.13	$	46.88	$	44.84

*There are no High or Low Volatile Met committed tons priced with collars.

Coal pricing for contracts with terms of one year or less is generally fixed. Coal pricing for multiple-year agreements generally provides the opportunity to periodically adjust the contract prices through pricing mechanisms consisting of one or more of the following:

•

Fixed price contracts with pre-established prices; or

•

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

•

Price 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.

The volume of coal to be delivered is specified in each of our coal contracts. Although the volume to be delivered under the coal contracts is stipulated, the parties may vary the timing of the deliveries within specified limits.

Coal contracts typically contain force majeure provisions allowing for the suspension of performance by either party for the duration of specified events. Force majeure events include, but are not limited to, labor disputes and unexpected significant geological conditions. Depending on the language of the contract, some contracts may terminate upon continuance of an event of force majeure that extends for a period greater than three to twelve months.

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, 2010 we operated 22 towboats, 5 harbor boats and a fleet of 620 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 2009 National Mining Association Survey to have produced approximately 53% (based on tonnage produced) of the total United States production in 2009. The U.S. Department of Energy reported 1,375 active coal mines in the United States in 2009, the latest year for which government statistics are available. Demand for our coal by our principal customers is affected by many factors including:

•

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

•

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 markets, both of which are significantly affected by international demand and competition.

Gas Operations

Our gas operations primarily produce coalbed methane (CBM), 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 found in formations less than 2,500 feet deep which are usually better defined than deeper formations. CONSOL Energy believes that this contributes to lower exploration costs than those incurred by producers that operate in deeper, less defined formations. Most of our CBM operations are located in central Appalachia in Southwest Virginia. CBM is our traditional and largest operation. Typically in this area we have produced CBM from vertical wells which we drill ahead of mining and gob gas wells which are drilled behind mining. Some of our CBM production comes from northern Appalachia in northwestern West Virginia and southwestern Pennsylvania where we drill vertical-to-horizontal CBM wells. In 2010, CBM production was 91.4 billion cubic feet (bcf) or 72% of our total gas production compared to 86.9 bcf, or 92% of our total gas production in 2009.

On April 30, 2010, CONSOL Energy completed the Dominion Acquisition for approximately $3.5 billion. The acquisition included approximately one trillion cubic feet equivalents (Tcfe) of net proved reserves and 1.46 million net acres of oil and gas rights within the Appalachian Basin. Included in the acreage holdings were approximately 500 thousand prospective net Marcellus Shale acres located predominantly in southwestern Pennsylvania and northern West Virginia. The producing wells acquired in the Dominion Acquisition are primarily vertical conventional wells located in northwest West Virginia and central Pennsylvania. The producing wells purchased in the acquisition have contributed to the increase in our conventional gas production

in the year ended December 31, 2010. In 2010, conventional production was 24.6 bcf or 19% of our total gas production compared to 1.7 bcf or 2% of total gas production in 2009.

With the Dominion Acquisition and other land activities, we have substantially increased our acreage position in the Marcellus Shale from approximately 250,000 at December 31, 2009 to approximately 752,000 at December 31, 2010. Our gas division has been focused on developing our Marcellus acreage position in southwest Pennsylvania, central Pennsylvania and northwest West Virginia. In the year ended December 31, 2010, we have drilled 24 horizontal Marcellus wells of which 13 were brought on-line. We also acquired 17 vertical Marcellus wells acquired in the Dominion Acquisition bringing our total well count to 52 Marcellus wells. Our horizontal Marcellus wells can have laterals up to 5,000 feet in length. Longer laterals allow for higher gas production with a proportionately smaller outlay of capital than drilling an additional vertical well with shorter laterals. These Marcellus wells produced 10.2 bcf in 2010 or 8% of our total gas production compared to 4.9 bcf or 5% of our total gas production in 2009.

We also have operations in central Ohio, eastern Tennessee, western Kentucky, Indiana and Illinois. We have continued to explore the shale and deeper formations in these areas. For example, we are conducting an exploration program in the Utica, the New Albany Shale and other shallow oil zones. In addition to these 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. Wells in these areas produced 1.7 bcf or 1% of our total gas production in 2010 compared to 0.9 bcf or less than 1% for our total gas production in 2009.

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

CBM

We have the rights to extract CBM in Virginia from approximately 356,000 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 core hole data that allows us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

We also have the right to extract CBM in northwestern West Virginia and southwestern Pennsylvania from approximately 858,000 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 information that allows us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

In central Pennsylvania we have the right to extract CBM from approximately 263,000 net CBM acres, which contain most of our recoverable coal reserves as well as significant leases from other coal owners. In addition, we control 841,000 net CBM acres in Illinois, Kentucky, Indiana, and Tennessee. We also 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, and 92,000 net acres in eastern Ohio and central West Virginia.

Marcellus Shale

We have substantially increased our acreage position in the Marcellus Shale from 250,000 net acres at December 31, 2009 to 752,000 net acres at December 31, 2010. The Dominion Acquisition contributed approximately 500,000 acres of the increase. CONSOL Energy drilled and completed 13 wells in the Marcellus Shale in southwestern and central Pennsylvania in 2010. The Dominion Acquisition also included 17 producing Marcellus wells, 12 of these wells are located in central Pennsylvania and 5 of these wells are located in northwestern West Virginia. We also had 11 Marcellus wells in process at December 31, 2010. At December 31, 2010 we have 52 producing Marcellus wells compared to 22 Marcellus wells in 2009.

Our Marcellus wells are primarily horizontal wells with 2,500 to 5,000 feet of lateral length. The longer lateral lengths allow for proportionately higher gas production from a single well compared to shorter length lateral wells. This allows for proportionately lower capital outlays compared to drilling shorter length lateral wells. The average lateral was 3,400 feet.

CONSOL Energy’s primary 2011 gas objective is to delineate the newly acquired Marcellus Shale acreage in central Pennsylvania and northern West Virginia. We also plan to extend the average lateral length to 4,000 feet and complete more frac stages which should improve well economics.

Conventional

In 2010, the Dominion Acquisition significantly contributed to the increased number of conventional wells from 195 at December 31, 2009 to 8,517 at December 31, 2010. The conventional wells acquired in the Dominion Acquisition were primarily located in northwestern West Virginia and central Pennsylvania. In 2010, we drilled and completed 23 shallow conventional wells in central Pennsylvania. Also, in 2010, we drilled and completed 86 conventional wells in West Virginia, three conventional wells in Kentucky, and two conventional wells in eastern Ohio. Currently, 32 conventional wells are waiting for the completion of gathering facilities for collection.

The majority of our conventional leasehold position is held by production and all of it is extensively overlain by existing third party gas gathering and transmission infrastructure. Conventional drilling in West Virginia and central Pennsylvania is characterized as low-cost and low-risk with success rates exceeding 98%. The conventional assets add great diversity to CONSOL Energy’s drilling portfolio, provide multiple synergies with our CBM and unconventional shale operations, and the held by production nature of the conventional properties affords CONSOL Energy considerable flexibility to choose when to exploit those assets.

CONSOL Energy also has the rights to extract conventional gas from approximately 650,000 net acres of shallow conventional potential in Ohio, Pennsylvania, West Virginia, and New York.

Other Gas

We control approximately 346,000 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 2,500-4,000 feet. In 2010, we participated with RPSEA (Research Partnership to Secure Energy for America) to better understand and further pursue the development of the vast New Albany Shale resources. As part of that effort, we drilled and completed two horizontal New Albany Shale wells, retrieved full bore core and conducted micro seismic analysis. In addition, we conducted the first ever simultaneous VaporFrac, a mixture of 95% nitrogen and 5% liquid in the fracturing fluid, essentially minimizing the liquids used in fracing wells. Two additional horizontal wellbores to further test the New Albany shale are planned for 2011.

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, and CONSOL Energy has found it to be rich in total organic content.

CONSOL Energy has 282,000 net acres of Chattanooga Shale. This largely contiguous acreage is composed of only a small number of leases, a rarity in Appalachia. CONSOL Energy is the operator of all of its Chattanooga Shale wells. CONSOL Energy 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.

We have 480,000 net acres of Huron shale potential in Kentucky and Virginia; a portion of this acreage has tight sands potential. CONSOL Energy also currently controls acreage in southeastern Ohio, southwestern Pennsylvania, and northern West Virginia underlain by Utica Shale potential. The thickness of the Utica Shale in this area ranges from 200 to 450 feet. Further delineation of this potential is planned for 2011, particularly in Ohio where the play is expected to be rich in liquid hydrocarbons.

Summary of Properties as of December 31, 2010


	Coalbed Methane Segment			Conventional Segment			Marcellus Segment			Other Gas Segment			Total
Estimated Net Proved Reserves (billion cubic feet equivalent)		1,789,385			983,589			859,396			99,227			3,731,597
Percent Developed		60	%		70	%		16	%		25	%		52	%
Net Producing Wells (including gob wells)		3,945			8,517			52			73			12,587

Net Proved Developed Acres		254,683			226,154			2,074			7,558			490,469
Net Proved Undeveloped Acres		72,819			44,847			10,285			11,993			139,944
Net Unproved Acres(1)		2,241,748			378,825			739,977			1,088,004			4,448,554

Total Net Acres(2)		2,569,250			649,826			752,336			1,107,555			5,078,967

(1)

Net acres include acreage attributable to our working interests of the properties. 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.

(2)

Acreage amounts are shown under the target strata CONSOL Energy expects to produce, although the reported acre may include rights to multiple gas seams (CBM, Conventional, Marcellus, etc.). We have reviewed our drilling plans, our acreage rights and used our best judgment to reflect the acre in the strata we expect to produce. As more information is obtained or circumstances change, the acreage classification may change.

Development Wells (Net)

During the years ended December 31, 2010, 2009 and 2008 we drilled 317, 247 and 534 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 2010 and one dry development well in 2009. There were no dry development wells in 2008. As of December 31, 2010, 21 wells are still in process. The following table illustrates the wells drilled by well classification type:


	For the Year Ended December 31,
	2010		2009		2008
Coalbed methane segment		184		228		534
Conventional segment		107		5		—
Marcellus segment		24		14		—
Other Gas segment		2		—		—

Total		317		247		534

Exploratory Wells (Net)

During the years ended December 31, 2010, 2009 and 2008, we drilled in the aggregate 38, 18 and 56 net exploratory wells, respectively. The following table illustrates the exploratory wells drilled by well classification type:


	For the Year Ended December 31,
	2010						2009						2008
	Producing		Dry		Still Eval.		Producing		Dry		Still Eval.		Producing		Dry		Still Eval.
Coalbed methane segment		—		—		—		2		—		—		3		—		10
Conventional segment		2		—		3		2		—		2		3		3		10
Marcellus segment		—		—		—		2		1		—		3		—		—
Other Gas segment		18		2		13		5		—		4		6		—		18

Total		20		2		16		11		1		6		15		3		38

Summary of Other Operating Data

Production

The following table sets forth net sales volumes produced for the periods indicated:


	For the Year Ended December 31,
	2010		2009		2008
	(in million cubic feet)
Coalbed methane segment		91,351		86,944		75,783
Conventional segment		24,599		1,663		174
Marcellus segment		10,195		4,950		394
Other Gas segment		1,730		858		211

Total Produced		127,875		94,415		76,562

Average Sales Price and Average Lifting Cost

The following table sets forth the total average sales price and the total average lifting cost for all of our gas production for the periods indicated, including intersegment transactions. Total lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization. See Part II Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations for a breakdown by segment.


	For the Year Ended December 31,
	2010		2009		2008
Average Gas Sales Price Before Effects of Financial Settlements (per thousand cubic feet)	$	4.53	$	4.15	$	8.99
Average Effects of Financial Settlements (per thousand cubic feet)	$	1.30	$	2.53	$	—
Average Gas Sales Price Including Effects of Financial Settlements (per thousand cubic feet)	$	5.83	$	6.68	$	8.99
Average Lifting Cost excluding ad valorem and severance taxes (per thousand cubic feet)	$	0.50	$	0.48	$	0.58

Producing Wells and Acreage

Most of our development wells and proved acreage are located in Virginia, West Virginia and Pennsylvania. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments or other term commitments are satisfied. The following table sets forth, at December 31, 2010, the number of producing wells, developed acreage and undeveloped acreage:


	Gross		Net(1)
Producing Wells (including gob wells)		14,747		12,587
Proved Developed Acreage		520,005		490,469
Proved Undeveloped Acreage		146,173		139,944
Unproven Acreage		5,014,495		4,448,554

Total Acreage		5,680,673		5,078,967

(1)

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 enter 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 52.1 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2010 at an average price of $7.66 per thousand cubic feet. 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. As of December 31, 2010, we expect these transactions will cover approximately 48.0 billion cubic feet of our estimated 2011 production at an average price of $5.56 per thousand cubic feet, 22.6 billion cubic feet of our estimated 2012 production at an average price of $6.20 per thousand cubic feet, 3.8 billion cubic feet of our estimated 2013 production at an average price of $5.16 per thousand cubic feet, and 3.8 billion cubic feet of our estimated 2014 production at an average price of $5.41 per thousand cubic feet.

We have purchased firm transportation capacity on various interstate pipelines to ensure gas production flows to market. As of December 31, 2010, we have secured firm transportation capacity to cover more than our 2011, 2012, 2013 and 2014 hedged production.

The hedging strategy and information regarding derivative instruments used are outlined in Part II Item 7A Qualitative and Quantitative Disclosures About Market Risk and in Note 23—Derivative Instruments in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.

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,
	2010		2009		2008
Proved developed reserves		1,931,272		1,040,257		783,290
Proved undeveloped reserves		1,800,325		871,134		638,756

Total proved developed and undeveloped reserves(a)		3,731,597		1,911,391		1,422,046

(a)	For additional information on our reserves, see “Other Supplemental Information—Supplemental Gas Data (unaudited) to the Consolidated Financial Statements in Item 8 of this Form 10-K.

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)
	2010		2009		2008
Future net cash flows	$	5,474	$	2,391	$	2,824
Total PV-10 measure of pre-tax discounted future net cash flows(1)	$	2,780	$	1,480	$	2,004
Total standardized measure of after tax discounted future net cash flows	$	1,661	$	894	$	1,218

(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 the 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 of the most directly comparable GAAP measure—after-tax discounted future net cash flows.

Reconciliation of PV-10 to Standardized Measure


	As of December 31,
	2010			2009			2008
	(Dollars in millions)
Future cash inflows	$	16,724		$	7,975		$	8,857
Future production costs		(5,176	)		(3,123	)		(3,526	)
Future development costs (including abandonments)		(2,720	)		(996	)		(794	)

Future net cash flows (pre-tax)		8,828			3,856			4,537
10% discount factor		(6,048	)		(2,376	)		(2,533	)

PV-10 (Non-GAAP measure)		2,780			1,480			2,004

Undiscounted income taxes		(3,354	)		(1,465	)		(1,714	)
10% discount factor		2,235			879			928

Discounted income taxes		(1,119	)		(586	)		(786	)

Standardized GAAP measure	$	1,661		$	894		$	1,218

Midstream Gas Services

CONSOL Energy has traditionally designed, built and operated natural gas gathering systems to move gas from the wellhead to interstate pipelines or other local pricing points. In addition, CONSOL Energy acquired extensive gathering assets in the Dominion Acquisition in 2010. CONSOL Energy now owns approximately 3,000 miles of gas gathering pipelines as well as 230,000 horsepower of compression, of which, approximately 80% is wholly owned with the balance being leased. Along with this compression capacity, CONSOL Energy owns and operates a number of gas processing facilities. This infrastructure is capable of delivering 200 billion cubic feet per year of pipeline quality gas.

This in-place gas infrastructure was primarily built to transport CONSOL Energy’s coalbed methane (CBM) production and shallow conventional gas. This system is generally not suited to move the higher pressure volumes associated with Marcellus wells. However, we believe that the network of right-of-ways, vast surface holdings and experience in building and operating gathering systems in the Appalachian basin will give CONSOL Energy a tremendous advantage in building the midstream assets required to develop CONSOL Energy’s Marcellus position.

CONSOL Energy has had the advantage of having gas production from CBM, which can be lower Btu than pipeline specification, as well as higher Btu Marcellus production which can complement each other by reducing and in some cases eliminating the need for costly processing of the CBM. In addition, the lower Btu CBM production offers an opportunity to blend ethane back into the gas stream when pricing or capacity for ethane markets dictate. This will allow CONSOL Energy more flexibility in bringing Marcellus on-line at qualities that meet interstate pipeline specifications.

In addition to the pipeline and processing assets, CONSOL Energy has access to water resources. Through legacy mining operations overlapping the footprint of our gas resources, CONSOL Energy has access to mine waters and the infrastructure to move water to locations where water is needed to support future gas operations. We believe that there are synergies between mining and gas operations around water resources that could give unique advantages to CONSOL Energy.

Competition

The United States natural gas industry is highly competitive. CONSOL Energy competes with other large producers, thousands of small producers as well as pipeline imports from Canada and Liquefied Natural Gas

(LNG) from around the globe. According to data from the Natural Gas Supply Association and the U.S. Department of Energy, the five largest producers of natural gas produced less than 19% of the total U.S. production in the first half of 2010. The U.S. Department of Energy reported almost 500,000 producing natural gas wells in the United States in 2009, the latest year for which government statistics are available.

CONSOL Energy’s gas operations are 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 various markets.

Continued demand for CONSOL Energy’s natural gas 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 alternative fuel supplies.

Power Generation

Through a joint venture with Allegheny Energy Supply Company, LLC, an affiliate of one of our largest coal customers, CONSOL Energy 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 our gas of up to 22 million cubic feet per day.

Other Operations

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) and river and dock 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 value from surface properties and right-of-ways in the development of gathering pipelines built for CONSOL Energy or for third parties;

•

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

•

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

•

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

CONSOL Energy’s objective is to improve the return on these assets without detracting from 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, drilling, and industrial supplies in the United States. Fairmont Supply has 33 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 and drilling supplies to CONSOL Energy’s mining and gas operations. Approximately 47% of Fairmont Supply’s sales in 2010 were made to CONSOL Energy’s coal and gas divisions.

Fairmont Supply Company’s subsidiary, Piping and Equipment Inc., 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 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 2010, approximately 11.2 million tons of coal were shipped through CONSOL Energy’s subsidiary, CNX Marine Terminal Inc.’s, exporting terminal in the Port of Baltimore. Approximately 34% 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 Corporation and CSX Transportation Inc.

River and Dock Services

CONSOL Energy’s river operations, located in Monessen, Pennsylvania, transport coal from our mines, coal from other mines and non-coal commodities from river loadout facilities located 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, 2010, we operated 22 towboats, 5 harbor boats and 620 barges. In 2010, our river vessels transported a total of 18.6 million tons of coal and other commodities, including 6.3 million tons of coal produced by CONSOL Energy mines.

CONSOL Energy provides dock services for our mines as well as 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.

Employee and Labor Relations

At December 31, 2010, CONSOL Energy had 8,630 employees, approximately 34% 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 2010 and will increase another $0.50 per hour in 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 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, 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, 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, management of electrical equipment containing polychlorinated biphenyls (PCBs), legislatively mandated benefits for current and retired coal miners, and employee health and safety. 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, all mining operations of CONSOL Energy entities must be maintained in compliance to avoid delay in issuance of necessary mining 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, the 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. Compliance with these laws has substantially increased the cost of mining and gas production for all domestic coal and gas producers. 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. 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. CONSOL Energy made capital expenditures for environmental control facilities of approximately $39.9 million, $50.4 million and $10.6 million in the years ended December 31, 2010, 2009 and 2008, respectively. The capital expenditures for environmental control facilities increased in 2009 primarily due to starting construction of an advanced water processing system at the Buchanan Mine. Construction of this facility was completed in 2010. CONSOL Energy expects to have capital expenditures of $62.4 million in 2011 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 civil penalties 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 refuge 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 replacement of existing seals in worked-out areas of mines with stronger seals;

•

the purchase of new fire resistant conveyor belting underground;

•

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

•

more stringent rock dusting requirements.

In addition, on October 14, 2010, the Mine Safety and Health Administration (MSHA) published a proposed rule to reduce the permissible concentration of respirable dust in underground coal mines from the current standard of 2 milligram per cubic meter of air to one milligram per cubic meter. MSHA is also likely to adopt new safety standards for proximity protection for miners that will require certain underground mining equipment to be equipped with devices that will shut the equipment down if a person is too close to the equipment to avoid injuries where individuals are caught between equipment and blocks of unmined coal.

Occupational Safety and Health Act

Our gas operations are subject to regulation under the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws in some states, all of which regulate health and safety of employees at our gas operations. Also, OSHA’s hazardous communication standard requires that information be maintained about hazardous materials used or produced by our gas operations and that this information be provided to employees, state and local governments and the public.

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

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a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner’s last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. 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 Patient Protection and Affordable Care Act (PPACA), which was implemented in 2010, made two changes to the Federal Black Lung Benefits Act. First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in coal mines and suffer from totally disabling lung disease. A coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner’s work. Second, it changed the law so black lung benefits being received by miners automatically go to their dependent survivors, regardless of the cause of the miner’s death. The impact of these law changes increased CONSOL Energy’s pneumoconiosis liability by approximately $46 million during the year ended December 31, 2010.

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 Plan 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 responsibility for unassigned beneficiaries (referred to as orphans) to the assigned operators. 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 NBCWA or a later NBCWA, and who subsequently goes out of business.

The Act requires some of our signatory 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 those plans. 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. Federal contributions were 75% in 2010. Federal contributions are expected to be 100% after 2010. In addition, federal contributions are also to be phased-in over the same period 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 and the 1993 Benefit Plan and certain AML 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 the Combined Fund and 1992 Benefit Plan 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 seven year period. The Pension Act includes a funding target phase-in provision consisting of a 96% funding target 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 2010 plan year funding ratio was 96%. 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:

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the Surface Mining Control and Reclamation Act of 1977,

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the Clean Air Act,

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the Clean Water Act,

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the Endangered Species Act,

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the Resource Conservation and Recovery Act,

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the Comprehensive Environmental Response, Compensation and Liability Act,

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the Toxic Substances Control Act, and

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the Emergency Planning and Community Right to Know 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. Liabilities above may be increased for 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. 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. 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 current per ton fee is $0.315 per ton 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.

In Pennsylvania, where CONSOL Energy operates three longwall mines, approximately $21.8 million and $30.3 million of expenses were incurred during the years ended December 31, 2010 and 2009, respectively, to mitigate and repair impacts on streams from subsidence. With respect to subsidence impacts to streams, the regulatory requirement to minimize impacts to the hydrologic balance 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 $24.2 million for the year ended December 31, 2011.

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.

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. Carbon dioxide, a greenhouse gas, is also emitted 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 the 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. In August 2010, the EPA published in the Federal Register the proposed Clean Air Transport Rule (the Transport Rule). The Transport Rule is intended to replace CAIR. The Transport Rule will allow minimal or no interstate trading. This will likely make compliance more expensive. The EPA’s schedule is to finalize the Transport Rule by July 2011. The first phase of the Transport Rule emission reductions will go into effect in 2012.

The installation of additional control measures to achieve regulatory emission 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 is developing emission limits for mercury for coal fired electric generating facilities under Section 112 of the Clean Air Act, which requires the EPA to impose maximum achievable control technology (“MACT”) limits. The EPA intends to issue proposed MACT regulations for mercury in March 2011 and to issue final MACT regulations in November 2011. 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 Clean Air Act and comparable state laws restrict the emission of air pollutants from compressor stations used in our gas operations. We may also be required to obtain pre-approval for construction or modification of certain facilities, to meet stringent air permit requirements, or to use specific equipment, technologies or best management practices to control emissions.

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 methane, and several states have adopted measures intended to reduce greenhouse gas loading in the atmosphere. Burning of coal and natural gas produce carbon dioxide. Also, natural gas and coalbed gas contain methane. If comprehensive legislation focusing on greenhouse gas (GHG) 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. 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 the EPA regulating GHGs under the Clean Air Act. Although, efforts to enact greenhouse gas legislation have failed, the EPA is proceeding with greenhouse gas regulations. In September 2009, the EPA finalized the Mandatory Reporting of Greenhouse Gas Rule. The current version of this rule requires reporting of emissions from coal mines and gas wells and associated facilities for 2011 emissions. In December 2010, the EPA announced a proposed schedule for establishing greenhouse gas emission limits for fossil fuel fired electric generating facilities (proposed regulations by July 2011 and final regulations by May 2012.) Such regulations could 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 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: improvement of designated “impaired waters” (not meeting state water quality standards) through the use of effluent limitations established so that all discharges to the “impaired” stream do not exceed Total Maximum Daily Load (“TMDL”) levels of the pollutants causing the impairment; 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; and the requirements to obtain permits for the discharge of produced wastes and other oil and gas wastes, or to dispose of such substances at approved disposal facilities. 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 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 relating to Section 404 permits and other permits and approvals required for coal mining operations. 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. A third initiative is to take a more active role in its review of NPDES permit applications for coal mining operations. A fourth initiative is EPA “guidance” to the states that instream specific conductance levels exceeding 500 microSiemens per centimeter is presumptive evidence that state narrative water quality standards which generally prohibit discharges harmful to aquatic life would be violated requiring the states to establish permit effluent limits to maintain instream specific conductance below 500 microSiemens per centimeter. Additionally, EPA’s initiatives are being supported by environmental groups. Two citizen groups recently filed a Clean Water Act citizen suit against a CONSOL Energy subsidiary alleging that discharges from a surface mine in West Virginia violate state water quality

standards in part because the specific conductance in the receiving stream exceeds the EPA benchmark of 500 microSiemens per centimeter. All of these initiatives have resulted in delays in the review and issuance of permits for surface coal mining operations, including applications for surface facilities for underground mines, such as applications for coal refuse disposal areas. 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. The EPA’s enhanced scrutiny initiatives have been challenged by the National Mining Association (“NMA”). On January 14, 2011, the U. S. District Court for the District of Columbia denied the EPA’s motion to dismiss the NMA’s complaint and also denied the NMA’s motion for a preliminary injunction of the EPA’s enhanced scrutiny initiatives. Although the NMA’s motion for a preliminary injunction was denied, the opinion contains holdings suggesting that the court may rule in favor of the NMA on the merits of the case. Unless the NMA is successful in its challenge of the EPA’s enhanced scrutiny of permit applications, we anticipate that it will continue to take longer to obtain permits and the costs of obtaining permits and compliance with permit conditions will increase significantly. These requirements may cause CONSOL Energy to incur additional costs that could adversely affect our operating results, financial condition and cash flows.

In December 2010, the Pennsylvania Department of Environmental Protection designated portions of the Monongahela River as impaired (not meeting state water quality standards) for sulfates in Pennsylvania’s biennial Integrated Water Quality Monitoring and Assessment Report to the EPA. The Clean Water act and corresponding state laws include requirements for improvement of designated “impaired waters” (not meeting state water quality standards) through the use of effluent limitations established so that all discharge to the “impaired” stream do not exceed the Total Maximum Daily Load (“TMDL”) levels of the pollutants causing the impairment. A TMDL accounts for existing loading of the pollutant (sulfates in this case) and sets a cumulative pollution load for the stream so as to prevent violations of state water quality standards. TMDL’s are used to set best management practices and set permit discharge limits. TMDL-based discharge limits are frequently more stringent than existing permit limits or often result in limits for pollutants that were not previously regulated. CONSOL Energy has one active underground mine and several closed mines in Pennsylvania that discharge into the Monongahela River. All of these operations could be subject to new effluent limits for sulfates that may result in the need to construct and operate expensive advanced water treatment facilities.

The EPA has announced that it will conduct a comprehensive study of the potential adverse impact that hydraulic fracturing may have on water quality and public health. Hydraulic fracturing is a way of producing gas from tight rock formations such as the Barnett and Marcellus shales. The EPA plans to initiate the study in January 2011 and have the initial study results available by late 2012. It is too early to predict what actions, if any, will result from the study.

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 for mining and gas operations, may delay issuance of mining permits, or may cause us to modify mining plans or develop and implement species-specific protection and enhancement 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 or produce gas from our properties.

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. We could incur liability under CERCLA relative to our coal

or gas operations. 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 released 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 (“coal 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 waste. 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. The proposed Coal Combustion Residuals Rule was published in June 2010. The public comment period ended on November 19, 2010. Industry and state regulatory agencies are trying to convince the EPA that the states are adequately regulating the 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.

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 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 gas 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, 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

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 on Form 10-K.

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 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, 2010, 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.

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

Economic conditions in a number of industries in which our customers operate, such as electric power generation and steel making, substantially deteriorated in recent years and reduced the demand for natural gas and coal. Although global industrial activity recovered in 2010 from 2009 levels, the continuation of the recovery, especially for industries in the United States and Europe, is uncertain. During recent years, financial markets in the United States, Europe and Asia also experienced unprecedented turmoil and upheaval. This was 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. Although we cannot predict the impacts, renewed weakness in the economic conditions of 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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demand for natural gas and electricity in the United States is impacted by industrial production, which if weakened would negatively impact the revenues, margins and profitability of our natural gas and steam coal business;

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demand for metallurgical coal hinges on steel demand in the United States and globally, which if weakened would negatively impact the revenues, margins and profitability of our metallurgical coal business;

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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 securitization 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; increased utilization by the steel industry of electric arc furnaces or pulverized coal processes to make steel which do not use furnace coke, an intermediate

product produced from metallurgical coal; 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 coal production, which would reduce our revenues.

Gas prices are closely linked to supply of natural gas and consumption patterns in the United States of the electric power 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 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. In particular, while demand for natural gas recovered to pre-recession levels, the U.S. natural gas industry continues to face concerns of oversupply due to the success of new shale plays and continued drilling in these plays, despite lower gas prices, to meet drilling commitments. 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. These include reduced cash flow, which would decrease funds available for capital expenditures employed to replace reserves or increase production. Also, our 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 an adverse effect on our results of operations in the period taken.

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

During the year ended December 31, 2010, approximately 89% 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 in our long-term coal contracts 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, 2010, we derived over 25% of our total revenues from sales to our four largest coal and gas customers. At December 31, 2010, we had approximately 21 coal supply agreements with these customers that expire at various times from 2011 to 2030. 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.

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 and gas 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 $200 million accounts receivable securitization program and our business could be adversely affected. In addition, if customers refuse 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. Similarly, our gas business depends on gathering, processing and transportation facilities owned by others and the disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our gas.

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.

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

Competition within the coal and gas industries may adversely affect our ability to sell our products. Increased competition or a loss of our competitive position could adversely affect our sales of, or our prices for, our coal and gas products, 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 electric 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 and wind 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 could encourage 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. We compete with these companies and we may compete with foreign companies for domestic sales. Many of the companies we compete with 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. 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 negotiate a new agreement with the United Mine Workers of America, if we enter into a new agreement which significantly increases our labor costs or if we otherwise fail to maintain satisfactory labor relations.

As of December 31, 2010, we had 8,630 employees. Approximately 34% of these employees are represented by the United Mine Workers of America (UMWA) and union operations generated approximately 49% of our U.S. coal production during the year ended December 31, 2010. Our current collective bargaining agreement with the UMWA expires on December 31, 2011. If we do not negotiate a new collective bargaining agreement with the UMWA, we may incur prolonged strikes and other work stoppages at our union mines. We may also have significant reductions in productivity which can materially adversely affect our business, financial condition and results of operations by significantly reducing our production and sale of coal. If we enter into a new agreement with the UMWA which significantly increases our labor costs relative to other coal companies, our ability to compete with other coal companies may be materially adversely affected. Satisfactory relations with our employees and organized labor is important to our success. If we do not maintain satisfactory labor relations, we may incur strikes, other work stoppages, or have reduced productivity.

The characteristics of coal may make it costly for electric power generators and other coal users to comply with various environmental standards regarding the emissions of impurities released when coal is burned which could cause utilities to replace coal-fired power plants with alternative fuels. In addition, various incentives have been proposed to encourage the generation of electricity from renewable energy sources. A reduction in the use of coal for electric power generation could decrease the volume of our coal sales and adversely affect our results of operation.

Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. Complying with regulations on the emissions of impurities can be costly for electric power generators. 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 electric power generators switch to alternative fuel could materially affect us. Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, or particulate matter 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 (EPA) 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. Additional reductions in permissible emission levels of impurities by coal-fired plants will likely make it more costly to operate coal-fired electric power plants and make coal a less attractive fuel alternative for electric power generation in the future.

Apart from actual and potential regulation of emissions from coal-fired plants, 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 reductions in the amount of coal consumed by domestic electric power generators as a result of current or new standards for the emission of impurities or incentives to switch to alternative fuels or renewable energy sources could reduce the demand for our coal, thereby reducing our revenues and adversely affecting our business and results of operations.

Regulation of greenhouse gas emissions as well as uncertainty concerning such regulation could adversely impact the market for coal and natural gas and the regulation of greenhouse gas emissions may increase our operating costs and reduce the value of our coal and gas assets.

While climate change legislation in the U.S. is unlikely in the next several years, the issue of 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 emissions into the atmosphere by coal and gas end users, such as coal-fired electric power generation 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. 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. Regulation of GHGs could occur in the United States pursuant to EPA regulation under the Clean Air Act. On December 23, 2010 the EPA announced that it will propose standards for GHG emissions for power plants in July 2011 and issue final standards in May 2012. 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 electric power generation plants which may make it more difficult for utilities to obtain financing for coal-fired plants.

If comprehensive regulation focusing on GHGs emission reductions is adopted for the United States by the EPA or in other countries where we sell coal, or if utilities were to have difficulty obtaining financing in connection with coal-fired plants, it may make it more costly to operate fossil fuel fired (especially coal-fired) electric power generation plants and make fossil fuels less attractive for electric utility power plants in the future. Depending on the nature of the regulation or legislation, natural gas-fueled power generation could become more economically attractive than coal-fueled power generation, substantially increasing the demand for natural gas. Apart from actual regulation, uncertainty over the regulation of GHG emissions may inhibit utilities from investing in the building of new coal-fired plants to replace older plants or investing in the upgrading of existing coal-fired plants. Any reduction in the amount of coal or possibly natural gas consumed by domestic electric power generators as a result of actual or potential regulation of greenhouse gas emissions could decrease demand for our fossil fuels, thereby reducing our revenues and materially and adversely affecting our business and results of operations. We or our customers may also have to invest in carbon dioxide capture and storage technologies in order to burn coal or natural gas and comply with future GHG emission standards.

In addition, 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 further reduce our methane emissions, pay higher taxes, incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines or perhaps curtail coal production. The amount of coalbed methane we capture is reported, on a voluntarily basis, to the U.S. Department of Energy. We have recorded the amounts we have captured since the early 1990’s.

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.

Our coal mining and gas operations are subject to operating risks, which could increase our operating expenses and decrease our production levels which could adversely affect our results of operations. Our coal and gas operations are also subject to hazards and any losses or liabilities we suffer from hazards which occur in our operations may not be fully covered by our insurance policies.

Our coal mining operations are predominantly underground mines. These mines are subject to a number of operating risks that could disrupt operations, decrease production and increase the cost of mining at particular mines for varying lengths of time thereby adversely affecting our operating results. In addition, if coal production declines, we may not be able to produce sufficient amounts of coal to deliver under our long-term coal contracts. CONSOL Energy’s inability to satisfy contractual obligations could result in our customers initiating claims against us. The operating risks that may have a significant impact on our coal operations include:

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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, explosions or other accidents;

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weather conditions; and

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security breaches or terroristic acts.

Our exploration for and production of natural gas also involves numerous operating risks. The cost of drilling, completing and operating wells for coalbed methane (CBM) or other gas is often uncertain, and a number of factors can delay or prevent drilling operations, decrease production and/or increase the cost of our gas operations at particular sites for varying lengths of time thereby adversely affecting our operating results. The operating risks that may have a significant impact on our gas operations include:

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unexpected drilling conditions;

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title problems;

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pressure or irregularities in geologic formations;

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equipment failures or repairs;

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fires, explosions or other accidents;

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adverse weather conditions;

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reductions in natural gas prices;

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security breaches or terroristic acts;

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pipeline ruptures; and

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

Although we maintain insurance for a number of hazards, we may not be insured or fully insured against the losses or liabilities that could arise from a significant accident in our coal or gas operations.

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 hold substantial acreage on which there are no proved gas reserves in Pennsylvania, Ohio, Kentucky, West Virginia and Tennessee. Over time, we plan to drill a number of wells in our undeveloped acreage. 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. 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 gas 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.

A decrease in the availability or increase in the costs of commodities, key services, or capital equipment used in mining or gas operations, such as steel, liquid fuels and rubber products we use in mining operations or drilling rigs we use to drill gas wells in our gas operations, 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 the costs of commodities, key services or capital equipment we use in our operations could impact our mining operations costs because we may have a limited ability to negotiate lower prices, and, in some cases, may not have a ready substitute.

In gas operations we contract with third parties for well services, related equipment, and qualified experienced field personnel to drill wells and conduct field operations. The demand for these services 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 increases in the costs 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 attempt to mitigate the risks involved with increased industrial activity by entering into “take or pay” contracts with well service providers which commit them to provide services to us at specified levels and commit us to pay for services at specified levels even if we do not use those services. However, these contracts expose us

to economic risk. For example, if the price of natural gas declines and it is not economical to drill and produce additional natural gas, we may have to pay for services that we did not use. This would decrease our cash flow and raise our costs of production.

For mining and drilling operations, CONSOL Energy must obtain, maintain, and renew governmental permits and approvals which if we cannot obtain in a timely fashion would reduce our production, cash flow and results of operations.

Most coal 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 the 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 permits for all types of coal mining operations, and has been recommending that a number of permits be denied because of alleged concerns by the EPA of potential impacts to water quality in streams below mining operations, with cumulative impacts of mining on watersheds. The 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 Clean Water Act Section 402 discharge permits and Section 404 dredge and 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, 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. These delays or denials of mining permits could reduce our production, cash flow and results of operations.

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 have increased our costs of doing business for both coal and gas, and may restrict both our coal and gas 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. These include 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. For example, we have agreed to commence operation by May 30, 2013 of a new advanced waste water treatment plant to treat the discharge of mine water from our Blacksville #2, Loveridge and Robinson Run mines. This treatment plant will cost an estimated $110 to $120 million to construct. 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” (not meeting state water quality standards) through the use of effluent limitations established so that all discharges to the “impaired” stream do not exceed Total Maximum Daily Load (“TMDL”) levels of the pollutants causing the impairment; 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 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, the 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 material in streams. In addition, CONSOL Energy incurs and will continue to incur 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 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. A mine could be shut down for an extended period of time if a disaster were to occur at it.

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. If a disaster were to occur at one of our mines, it could be shutdown for an extended period of time and our reputation with our customers could be materially damaged.

In West Virginia there are areas where drainage from coal mining operations contains concentrations of selenium that without treatment would result in violations of state water quality standards that are set to protect fish and other aquatic life. CONSOL Energy has two operations with selenium discharges. CONSOL Energy and other coal companies are working to expeditiously develop cost effective means to remove selenium from mine water. If such technology is not developed promptly, the only available effective treatment technologies are expensive to construct and operate which will increase coal production costs.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in liabilities to us.

Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage.” We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or for the entire share.

We maintain extensive coal refuse areas and slurry impoundments at a number of our mining complexes. Such areas and impoundments are subject to extensive regulation. Our coal refuse areas and slurry impoundments are designed, constructed, and inspected by our company and by regulatory authorities according to stringent environmental and safety standards. Structural failure of a slurry impoundment or coal refuse area could result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.

These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us.

CONSOL Energy has reclamation, mine closing 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. Also, state laws require us to plug gas wells and reclaim well sites after the useful life of our gas wells has ended. 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 $671 million at December 31, 2010. 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 and gas 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 coal reserve estimates include:

•

geological conditions;

•

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

•

the assumed effects of regulations and taxes by governmental agencies;

•

assumptions governing future prices; and

•

future operating costs, including the cost of materials.

Similarly, natural gas reserves require subjective estimates of underground accumulations of natural gas and assumptions concerning natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved gas 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 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 gas reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of gas 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 gas 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;

•

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 gas reserves as of December 31, 2010 would decrease from $2.8 billion to $2.7 billion. The standardized Generally Accepted Accounting Principle measure associated with this decline of $0.10 per thousand cubic feet, would be approximately $1.6 billion.

Each of the factors which impacts reserve estimation may in fact vary considerably from the assumptions used in estimating the reserves. For these reasons, estimates of coal and gas reserves may vary substantially. Actual production, revenues and expenditures with respect to our coal and gas reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual coal and gas reserves.

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

While chain of title for our coal estate generally has been established, there may be defects in it that we do not realize until we have committed to developing those properties or coal reserves. As such, the title to the coal estate that we intend to mine may contain defects. In order to conduct our mining operations on properties where these defects exist, we may incur unanticipated costs perfecting title.

Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. Many 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 established, in some cases, the gas estate title work is less developed. 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 subsidiaries, primarily Fairmont Supply Company, 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, Texas 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, 2010, payments by Fairmont with respect to asbestos cases have not been material. Other of our subsidiaries may also have asbestos claims against them. 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 and its subsidiaries are subject to various legal proceedings, which may have an adverse effect on our business.

We are party to a number of legal proceedings in the normal course of business activities. Defending these actions, especially purported class actions, can be costly, and can distract management. For example, we are a

defendant in four pending purported class action lawsuits dealing with such diverse matters as the propriety of our acquisition of the noncontrolling interest of CNX Gas, our right to natural gas production in some areas, and asserting that we are responsible for Hurricane Katrina and the damage it caused. There is the potential that the costs of defending litigation in 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—Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion of pending legal proceedings.

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, 2010, the current and non-current portions of these obligations included:

•

postretirement medical and life insurance ($3.3 billion);

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coal workers’ black lung benefits ($184.5 million);

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salaried retirement benefits ($163.4 million); and

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workers’ compensation ($174.5 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 un-funded. 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 information available from the plan’s administrators, 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 in the case of 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 an increase in our proportionate share of the pension plan’s unfunded vested benefits at the time of the 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 plan in which we participate.

Certain subsidiaries of CONSOL Energy participate in a defined benefit multi-employer pension plan (1974 Pension Trust) negotiated with the United Mine Workers of America (UMWA) and contained in the National

Bituminous Coal Wage Agreement (NBCWA). The 1974 Pension Trust is overseen by a board of trustees, consisting of two union-appointed trustees and two employer-appointed trustees. The trustees’ responsibilities include selection of the plan’s investment policy, asset allocation, individual investment of plan assets and the administration of the plan. The benefits provided by the 1974 Pension Trust to the participating employees are determined based on age and years of service at retirement. The current 2007 NBCWA will expire on December 31, 2011 and calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The contribution rates called for by the current NBCWA are: $3.50 per hour worked in 2008; $4.25 per hour worked in 2009, $5.00 per hour worked in 2010 and $5.50 per hour worked in 2011. For the plan year ended June 30, 2010, approximately 18% of retirees and surviving spouses receiving benefits from the 1974 Pension Trust last worked at signatory subsidiaries of CONSOL Energy.

As of June 30, 2010, the most recent date for which information is available, the 1974 Pension Trust was underfunded. This determination was made in accordance with Employer Retirement Income Security Act of 1974 (ERISA) calculations, with a total actuarial asset value of $5.1 billion and a total actuarial accrued liability of $6.8 billion, or a funded percentage of approximately 76%. On October 7, 2010, certain subsidiaries of CONSOL Energy received notice from the trustees of the 1974 Pension Trust stating that the plan is considered to be “seriously endangered” for the plan year beginning July 1, 2010. Under the Pension Protection Act (Pension Act), a funded percentage of 80% should be maintained for this multi-employer pension plan, and if the plan is determined to have a funded percentage 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. The funded percentage certified by the actuary for the 1974 Pension Trust was determined to be approximately 76% under the Pension Act.

Certain subsidiaries of CONSOL Energy face risks and uncertainties by participating in the 1974 Pension Trust. All assets contributed to the plan are pooled and available to provide benefits for all participants and beneficiaries. As a result, contributions made by signatory subsidiaries of CONSOL Energy benefit employees of other employers. If the 1974 Pension Trust fails to meet ERISA’s minimum funding requirements or fails to develop and adopt a required rehabilitation plan, a nondeductible excise tax of five percent of the accumulated funding deficiency may be imposed on an employer’s contribution to this multi-employer pension plan. As a result of the 1974 Pension Trust’s “seriously endangered” status, steps must be taken under the Pension Act to improve the funded status of the plan. These steps could result in requiring certain signatory subsidiaries of CONSOL Energy to make additional contributions pursuant to a funding improvement plan adopted and implemented in accordance with the Pension Act and, therefore, could have a material impact on our operating results. See Note 17—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion.

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 reduce operating results.

CONSOL Energy’s defined benefit pension plans 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 reduction in operating results.

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 and to the extent we engage in divestitures, the timing and proceeds thereof may not provide anticipated benefits.

On April 30, 2010 we completed the Dominion Acquisition for approximately $3.5 billion. We could encounter difficulties with the Dominion Acquisition, such as the need to revisit assumptions about gas reserves, future gas production, revenues, capital expenditures and operating costs, including realizing anticipated synergies, the loss of key employees or commercial relationships or the need to address unanticipated liabilities. If we cannot successfully integrate our business, we may fail to realize the expected benefits of the acquisition. We also 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 an 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;

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unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion of the acquisition opportunity; and

•

we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.

From time to time part of our business and financing plans include the divestiture of certain assets. However, we do not control the timing or the terms associated with them. Divestitures may not provide anticipated benefits or anticipated proceeds and may not occur when forecasted.

CONSOL Energy’s rights plan may have anti-takeover effects that may discourage a change of control even if doing so might be beneficial to our stockholders.

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 of 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.

Our financial performance could be adversely affected by our debt.

As of December 31, 2010, our total indebtedness was approximately $3.695 billion of which approximately $155 million was under our senior secured credit facility, $129 million was under CNX Gas secured revolving

credit facility, $200 million was under the securitization facility, $250 million was under our 7.875% senior secured notes due March 2012, $1.5 billion was under our 8.00% senior unsecured notes due April 2017, $1.25 billion was under our 8.25% senior unsecured notes due April 2020, $103 million was under our Baltimore Port Facility 5.75% revenue bonds due September 2025, $66 million of capitalized leases due through 2021, and $42 million of miscellaneous debt. The degree to which we are leveraged could have important consequences, including, but not limited to:

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increasing our vulnerability to general adverse economic and industry conditions;

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limiting our ability to obtain additional financing to fund future working capital, capital expenditures, acquisitions, development of our coal and gas reserves or other general corporate requirements;

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limiting our flexibility in planning for, or reacting to, changes in our business and in the coal and gas industries; and

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placing us at a competitive disadvantage compared to less leveraged competitors.

Our senior secured credit facility and the indentures governing our 7.875% senior secured notes, and our 8.00% and 8.25% senior unsecured notes limit the incurrence of additional indebtedness unless specified tests or exceptions are met. In addition, our senior secured credit agreement and the indentures governing our 8.00% and 8.25% senior unsecured notes subject us to financial and/or other restrictive covenants. Under our senior secured credit agreement, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio, a maximum leverage ratio, and a maximum senior secured leverage ratio, as defined. Our senior secured credit agreement and the indentures governing our 8.00% and 8.25% senior unsecured notes impose a number of restrictions upon us, such as restrictions on granting liens on our assets, making investments in joint ventures, paying dividends, selling assets and engaging in acquisitions. Failure by us to comply with these covenants could result in an event of default that, if not cured or waived, could have an adverse effect on us.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our senior secured credit agreement and the indentures governing our 8.00% and 8.25% senior unsecured notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

Unless we replace our gas reserves, our gas 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, 2010, 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 shale gas drilling and production operations requires both adequate sources of water to use in the fracturing process as well as the ability to dispose of water after hydraulic fracturing. Our CBM gas drilling and production operations also require the removal and disposal of water from the coal seams from which we produce gas. If we cannot find adequate sources of water for our use or are unable to dispose of the water we use or remove it from the strata at a reasonable cost and within applicable environmental rules, our ability to produce gas economically and in commercial quantities could be impaired.

As part of our drilling and production in the Marcellus shale, we use hydraulic fracturing processes. Thus, we need access to adequate sources of water to use in our Marcellus shale operations. Further, we must remove the water that we use to fracture our shale gas wells when it flows back to the well-bore. In addition, in our CBM drilling and production, coal seams frequently contain water that must be removed and disposed of in order for the gas to detach from the coal and flow to the well bore. Our inability to locate sufficient amounts of water with respect to our Marcellus Shale operations, or the inability to dispose of or recycle water used in our Marcellus shale and our CBM operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste. These include, but are not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. These impositions 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. For example, concerns over the impact of hydraulic fracturing on watersheds have led to a moratorium on drilling in the Marcellus shale in New York State.

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 January 24, 2011, we had hedges on approximately 69.2 billion cubic feet of our 2011 natural gas production, 26.4 billion cubic feet of our 2012 natural gas production, 7.5 billion cubic feet of our 2013 natural gas production and 7.5 billion cubic feet of our 2014 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:

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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 the seventeenth paragraphs of Note 24—Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 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.

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, 2010:
Quarter Ended March 31, 2010	$	56.34	$	42.28	$	0.10
Quarter Ended June 30, 2010	$	46.26	$	33.73	$	0.10
Quarter Ended September 30, 2010	$	39.22	$	31.21	$	0.10
Quarter Ended December 31, 2010	$	48.81	$	36.67	$	0.10
Year Period Ended December 31, 2009:
Quarter Ended March 31, 2009	$	36.59	$	22.58	$	0.10
Quarter Ended June 30, 2009	$	43.57	$	24.57	$	0.10
Quarter Ended September 30, 2009	$	49.28	$	29.75	$	0.10
Quarter Ended December 31, 2009	$	52.87	$	42.81	$	0.10

As of December 31, 2010, there were 176 holders of record of our common stock.

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., Chesapeake Energy Corp., Cimarex 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 Westmoreland Coal Co. The graph assumes that the value of the investment in CONSOL Energy common stock and each index was $100 at December 31, 2005. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2010.


	2005		2006		2007		2008		2009		2010
CONSOL Energy Inc.		100.0		99.4		222.3		90.0		158.1		156.0
Peer Group		100.0		100.7		146.7		104.7		152.7		168.1
S&P 500 Stock Index		100.0		115.6		121.8		77.2		97.3		111.7

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 28, 2011, CONSOL Energy’s board of directors declared a regular quarterly dividend of $0.10 per share, payable on February 18, 2011, to shareholders of record on February 8, 2011.

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 in excess of an annual rate of $0.40 per share when our leverage ratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 3.48 to 1.00 and our availability was approximately $1.1 billion at December 31, 2010. The credit facility does not permit dividend payments in the event of default. The indentures to the 2017 and 2020 notes limits dividends to $0.40 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults under our credit facility or the indentures in the year ended December 31, 2010.

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, 2010, 2009, 2008, 2007 and 2006 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, 2010 presentation. 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,
	2010			2009			2008			2007			2006
Sales—Outside(A)	$	4,938,703		$	4,311,791		$	4,181,569		$	3,324,346		$	3,286,522
Sales—Purchased Gas(A)		11,227			7,040			8,464			7,628			43,973
Sales—Gas Royalty Interests(A)		62,869			40,951			79,302			46,586			51,054
Freight—Outside(A)		125,715			148,907			216,968			186,909			162,761
Other Income		97,507			113,186			166,142			196,728			170,861

Total Revenue and Other Income		5,236,021			4,621,875			4,652,445			3,762,197			3,715,171
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)		3,262,327			2,757,052			2,843,203			2,352,000			2,249,776
Acquisition and Financing Fees		65,363			—			—			—			—
Purchased Gas Costs		9,736			6,442			8,175			7,162			44,843
Gas Royalty Interests Costs		53,775			32,376			73,962			39,921			41,879
Freight Expense		125,544			148,907			216,968			186,909			162,761
Selling, General and Administrative Expenses		150,210			130,704			124,543			108,664			91,150
Depreciation, Depletion and Amortization		567,663			437,417			389,621			324,715			296,237
Interest Expense		205,032			31,419			36,183			30,851			25,066
Taxes Other Than Income		328,458			289,941			289,990			258,926			252,539
Black Lung Excise Tax Refund		—			(728	)		(55,795	)		24,092			—

Total Costs		4,768,108			3,833,530			3,926,850			3,333,240			3,164,251

Earnings Before Income Taxes		467,913			788,345			725,595			428,957			550,920
Income Taxes		109,287			221,203			239,934			136,137			112,430

Net Income		358,626			567,142			485,661			292,820			438,490
Less: Net Income Attributable to Noncontrolling Interest		(11,845	)		(27,425	)		(43,191	)		(25,038	)		(29,608	)

Net Income Attributable to CONSOL Energy Inc. Shareholders	$	346,781		$	539,717		$	442,470		$	267,782		$	408,882

Earnings Per Share:
Basic(B)	$	1.61		$	2.99		$	2.43		$	1.47		$	2.23

Dilutive(B)	$	1.60		$	2.95		$	2.40		$	1.45		$	2.20

Weighted Average Number of Common Shares Outstanding:
Basic		214,920,561			180,693,243			182,386,011			182,050,627			183,354,732

Dilutive		217,037,804			182,821,136			184,679,592			184,149,751			185,638,106

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

BALANCE SHEET DATA

(In thousands)


	December 31,
	2010			2009			2008			2007			2006
Working (deficiency) capital	$	(549,779	)	$	(487,550	)	$	(527,926	)	$	(333,242	)	$	174,372
Total assets		12,070,610			7,775,401			7,535,458			6,333,490			5,663,332
Short-term debt		484,000			522,850			722,700			372,900			—
Long-term debt (including current portion)		3,210,921			468,302			490,752			507,208			552,263
Total deferred credits and other liabilities		4,283,674			3,849,428			3,716,021			3,325,231			3,228,653
CONSOL Energy Inc. Stockholders’ equity		2,944,477			1,785,548			1,462,187			1,214,419			1,066,151

OTHER OPERATING DATA

(unaudited)


	Years Ended December 31,
	2010		2009		2008		2007		2006
Coal:
Tons sold (in thousands)(C)(D)		63,906		58,123		66,236		65,462		68,920
Tons produced (in thousands)(D)		62,352		59,389		65,077		64,617		67,432
Productivity (tons per manday)(D)		34.39		38.21		36.80		41.29		38.41
Average production cost ($ per ton produced)(D)	$	46.55	$	44.87	$	41.08	$	33.68	$	32.53
Average sales price of tons produced ($ per ton produced)(D)	$	61.35	$	58.28	$	48.77	$	40.60	$	38.99
Recoverable coal reserves (tons in millions)(D)(E)		4,401		4,520		4,543		4,526		4,272
Number of active mining complexes (at end of period)		12		11		17		15		14
Gas:
Net sales volumes produced (in billion cubic feet)(D)		127.9		94.4		76.6		58.3		56.1
Average sales price ($ per mcf)(D)(F)	$	5.83	$	6.68	$	8.99	$	7.20	$	7.04
Average cost ($ per mcf)(D)	$	3.90	$	3.44	$	3.67	$	3.33	$	2.88
Proved reserves (in billion cubic feet)(D)(G)		3,732		1,911		1,422		1,343		1,265

CASH FLOW STATEMENT DATA

(In thousands)


	For the Years Ended December 31,
	2010			2009			2008			2007			2006
Net cash provided by operating activities	$	1,131,312		$	1,060,451		$	989,864		$	558,633		$	664,547
Net cash used in investing activities(H)		(5,543,974	)		(845,341	)		(1,098,856	)		(972,104	)		(661,546	)
Net cash provided by (used in) financing activities		4,379,849			(288,015	)		205,853			231,239			(119,758	)

OTHER FINANCIAL DATA

(Unaudited)

(In thousands)


	Years Ended December 31,
	2010		2009		2008		2007		2006
Capital expenditures	$	1,154,024	$	920,080	$	1,061,669	$	743,114	$	690,546
EBIT(I)		653,458		786,520		685,574		421,978		531,009
EBITDA(I)		1,221,121		1,223,937		1,075,195		746,693		827,246
Ratio of earnings to fixed charges(J)		2.74		11.76		10.67		7.48		11.36

(A)	See Note 25—Segment Information in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K 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 2,117,243 shares, 2,127,893 shares, 2,293,581 shares, 2,099,124 shares, and 2,283,374 shares for the year ended December 31, 2010, 2009, 2008, 2007, and 2006, respectively.

(C)

Includes sales of coal produced by CONSOL Energy and purchased from third parties. Of the tons sold, CONSOL Energy purchased the following amount from third parties: 0.3 million tons in the year ended December 31, 2010, 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.

(D)

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 172, 170, 171 and 179 tons at December 31, 2010, 2009, 2008 and 2007 respectively. Sales of coal produced by equity affiliates were 0.6 million tons in the year ended December 31, 2010, 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 tons in the year ended December 31, 2007. Recoverable reserves and production amounts related to 2006 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, 2010, 2009 and 2008. The proportionate share of proved gas reserves for equity affiliates was 3.6 Bcfe at December 31, 2007 and 2.2 Bcfe at December 31, 2006. Sales of gas produced by equity affiliates were 0.32 Bcfe for the year ended December 31, 2007 and 0.22 Bcfe for the year ended December 2006.

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

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

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

(H)	Net cash used in investing activities includes $3,470,212 and $991,034 in the year ended December 31, 2010 related to the Dominion Acquisition and the purchase of CNX Gas Non-Controlling Interest, respectively. The year ended December 31, 2007 includes $296,724 related to the acquisition of AMVEST.

(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:


	Years Ended December 31,
	2010			2009			2008			2007			2006
Net Income	$	346,781		$	539,717		$	442,470		$	267,782		$	408,882
Add: Interest expense		205,032			31,419			36,183			30,851			25,066
Less: Interest income		(7,642	)		(5,052	)		(2,363	)		(12,792	)		(15,369	)
Less: Interest income included in black lung excise tax refund		—			(767	)		(30,650	)		—			—
Add: Income tax expense		109,287			221,203			239,934			136,137			112,430

Earnings before interest and taxes (EBIT)		653,458			786,520			685,574			421,978			531,009
Add: Depreciation, depletion and amortization		567,663			437,417			389,621			324,715			296,237

Earnings before interest, taxes and depreciation, depletion and amortization (EBITDA)	$	1,221,121		$	1,223,937		$	1,075,195		$	746,693		$	827,246

(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 global recovery for steel producers continued to gain strength in 2010. Global blast furnace iron production was 15% higher in 2010 than 2009. It is expected that global steel production rates will grow another 5-6% in 2011. The recent flooding in Australia has heightened steel producers’ concerns over security of supply of metallurgical coals. We believe that steel producers who have a large exposure to limited geographic supply sources will diversify their supply base to reduce the risk of supply disruptions. We believe this will increase the demand for U.S. metallurgical coals.

Demand for U.S. metallurgical coal is expected to be very strong in 2011 due to global growth as well as improving domestic demand. U.S. steel mill utilization is currently at 72%, and there are increasingly optimistic signs for the domestic metallurgical coal markets. Prices for hot rolled coil steel (HRC) have been steadily increasing, buoyed by strong U.S. auto sales figures in December 2010. U.S. auto markets are expected to continue recovery in 2011, which will improve the outlook for the North American steel markets. Given the continued projected growth in the global markets as well as an accelerating North American recovery, we anticipate that metallurgical coal markets will gain strength through 2011.

The steam coal outlook continues to improve, driven by declining inventories and increasing demand due to general economic recovery and favorable weather. Coal inventories at utilities were steadily drawn down in 2010. We believe that inventories at the end of December were 22-25 million tons below inventories at the same time last year. We believe that bituminous coal comprises half of this reduction in inventories and inventories in our major market areas (Mid Atlantic and South Atlantic markets) are lower than in other regions of the U.S.

Demand for Northern Appalachian coal is not only influenced by domestic demand from utilities but also from European utilities and cross-over demand from metallurgical markets. We expect European demand for U.S. coal to be very strong in 2011 as European coal prices have recently hit two-year highs. South African and Colombian coals continue to be pulled to developing countries like, China, Brazil and India, allowing North America coal to fill the void. We expect 2011 demand for Northern Appalachian coal will be very strong from four sources: traditional markets, as a metallurgical crossover product, as a replacement for declining Central Appalachian production and from European utilities.

A strong start to the 2010 winter season has helped improve natural gas demand; however, the natural gas industry continues to face concerns of oversupply. The supply of natural gas remains very strong due to the success of new shale plays and drilling in these plays to meet drilling commitments. Natural gas storage for 2010 is similar to 2009 levels and industrial demand for gas continues to grow as the economy recovers. In addition to small increases in demand, we are seeing more supply responses to the current price environment. Canadian gas imports have decreased and liquefied natural gas (LNG) imports have failed to materialize. We are also seeing more companies redirect capital away from lower return gas basins towards liquids rich targets. We expect these trends to help curb the growth in gas supply over the next one to two years.

Several significant transactions occurred in the year ended December 31, 2010, including the following;

•

On April 30, 2010, CONSOL Energy completed the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc., (Dominion Acquisition) for a cash payment of approximately $3.5 billion, which was principally allocated to oil and gas properties, wells and well related equipment. The acquisition included approximately 1 trillion cubic feet equivalents (Tcfe) of net proved reserves and 1.46 million acres of oil and gas rights within the Appalachian Basin. Included in the acquired acreage are approximately 500 thousand prospective net Marcellus Shale acres located predominantly in southwestern Pennsylvania and northern West Virginia. The acquisition enhances CONSOL Energy’s position in the strategic Marcellus Shale fairway by increasing its development assets.

•

On March 31, 2010, CONSOL Energy completed an offering of 44.3 million shares of common stock, which generated net proceeds of approximately $1.8 billion. On April 1, 2010, CONSOL Energy issued $1.5 billion of 8.00% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020. The equity and senior note proceeds were used in part to complete the Dominion Acquisition. CONSOL Energy also amended and expanded its previous $1.0 billion revolving credit facility to $1.5 billion. CNX Gas also amended and expanded its previous $200 million revolving credit facility to $700 million. These revolving credit facilities were amended and expanded to provide liquidity for future cash needs of the company.

•

On June 1, 2010, CONSOL Energy completed the acquisition of the outstanding shares of CNX Gas common stock that it did not previously own for a cash payment of approximately $967 million. The transaction was effected by means of a cash tender offer for CNX Gas shares at a price of $38.25 per share, followed by a short-form merger at the same price, in which CNX Gas became a wholly owned subsidiary of CONSOL Energy. CONSOL Energy previously owned approximately 83.3% of the approximately 151 million shares of CNX Gas common stock outstanding. An additional $24 million cash payment was made to cancel previously vested CNX Gas stock options. CONSOL Energy financed the acquisition of CNX Gas shares by means of internally generated funds, borrowings under its credit facilities and proceeds from its March 31, 2010 offering of common stock.

•

CONSOL Energy sold approximately 2.4 million tons of high volatile metallurgical coal overseas in 2010, to meet the growing global demand for steel and steel products. This coal was previously sold by CONSOL Energy on the domestic steam market at lower average sales prices. The new market for this coal has allowed expanded margins for coals we produce primarily from the Pittsburgh #8 seam.

•

CONSOL Energy sold approximately 4.6 million tons of low volatile metallurgical coal produced at our Buchanan Mine, of which approximately 72% was sold into the overseas metallurgical market at higher average prices than CONSOL Energy has received in the recent past.

•

CONSOL Energy’s gas operations, together with the producing wells purchased in the Dominion Acquisition, produced a record 127.9 billion cubic feet of gas. Although gas prices remain depressed, increased production has contributed to CONSOL Energy’s net income.

Because of the rapidly changing regulatory environment in which CONSOL Energy operates and various other issues that impact our industries, costs of our coal and gas production in the future may be impacted. The impacts of these changes cannot be determined with certainty at this time. Situations that may impact our costs include the following items:

•

As a result of mine disasters as well as a continuing effort to improve the safety of coal mining, state and federal mine regulators have recently adopted and proposed new mine safety requirements, which impact our operations. These regulations include, for example: new standards for the incombustible content of combined coal dust, rock dust and other dust in underground coal mines; new standards for the amount of respirable dust in underground coal mines; the requirement to equip underground mining equipment with proximity detection devices capable of shutting the equipment down if a person gets too close to the equipment; and the requirements to replace existing seals underground with stronger seals and to monitor and regulate the quality of the mine atmosphere in sealed areas to prevent explosions or reduce their impact. Further, it is likely that regulatory authorities will increase the number of inspections at coal mines and will more strictly enforce existing safety laws and regulations. New safety requirements and enhanced enforcement efforts typically increase the costs of our coal mining operations, which would impact our margins and results of operations.

•

State and Federal environmental regulators have recently adopted and proposed new environmental regulations, and adopted new interpretations of existing regulations, which impact our operations. These include: mandatory reporting of greenhouse gas emissions from underground coal mines and gas operations; potential regulation of greenhouse gas emissions from coal fired electric generating facilities, a significant market for our coal; adoption of more stringent emission limits for currently

regulated pollutants from coal fired electric generating facilities; regulation of coal combustion residuals under the Resource Conservation and Recovery Act; potential regulation of hydraulic fracturing of gas wells; more stringent interpretations of Clean Water Act requirements resulting in the need to remove constituents of mine drainage that cannot be removed with existing treatment facilities, and/or limiting areas that can be mined; more involvement by the EPA in review of applications for new mines and renewals of applications for existing mines resulting in significant permit delays; and reconsideration of regulations relating to conducting surface mining operations near streams. Such new and enhanced environmental protection requirements are likely to increase the costs of our coal mining operations, which would impact our margins and results of operations.

•

Enactment of laws or passage of regulations by the federal government, individual states or other countries regarding emissions from combustion of fossil fuels or establishing renewable energy standards could result in decreased consumption of coal and gas and lead to the switching to other energy technologies for electricity. While climate change legislation in the U.S. is unlikely in the next several years, it is likely that some form of legislation addressing global climate change or establishing renewable energy standards, or both, will be enacted in the future. At this time it is not possible to determine when such legislation will be enacted or the impact of potential legislation on our operations or financial condition. Whether or not climate change legislation is enacted, the U.S. Environmental Protection Agency (EPA) has found that carbon dioxide may reasonably be anticipated to “endanger public health or welfare” (an endangerment finding) under the Clean Air Act and is proposing regulations that would restrict carbon dioxide emissions from certain sources; however, the EPA’s endangerment finding and its authority to adopt such regulations is being challenged in the courts. Although, efforts to enact greenhouse gas legislation have failed, the EPA is proceeding with greenhouse gas regulations. In September 2009, the EPA finalized the Mandatory Reporting of Greenhouse Gas Rule. The current version of this rule requires reporting of emissions from coal mines and gas wells and associated facilities. In December 2010, the EPA announced a proposed schedule for establishing greenhouse gas emission limits for fossil fuel fired electric generating facilities (proposed regulations by July 2011 and final regulations by May 2012.) The level of impact will depend on numerous factors including the specific requirements imposed by legislation or rules, the timing of legislation or rules, time period for compliance, and the timing and commercial development of technologies associated with carbon capture and sequestration. Ultimately, the impact of possible legislation or rules on our business will depend on the degree to which electric power generators are forced to reduce their consumption of coal or gas, install expensive technologies for carbon capture and sequestration, or switch to alternative energy sources. CONSOL Energy believes that if climate change legislation or rules are passed, gas will be impacted to a lesser degree than coal and the company has made strategic investment decisions to change its portfolio of assets to increase the contribution of gas to the company’s business. In fact, over the short term, CONSOL Energy expects gas to be the preferred fuel source for new power plants. Over the long term, CONSOL Energy believes that with the development of new technologies for carbon capture and sequestration, both coal and gas will continue to be used as clean and competitive fuel sources for electricity generation.

•

As standards continue to become more stringent on water discharge quality, CONSOL Energy will incur additional costs to build and operate facilities to treat water. For example, CONSOL Energy completed construction of a new mine water treatment facility at its Buchanan Mine in Virginia in 2010 for a total cost of approximately $86 million. It is also in the process of designing and permitting another facility to process mine water from the active Blacksville #2, Loveridge and Robinson Run Mines and the closed Four States Mine in northern West Virginia. The existing facility and the one being permitted are designed to remove chlorides to insure compliance with state and Federal water discharge standards. These new facilities will also remove other dissolved constituents, such as sulfates. Construction of the West Virginia facility is scheduled to be completed in 2013 with a total estimated cost of approximately $110 million to $120 million. These facilities utilize state of the art equipment for water treatment including reverse osmosis, evaporation and crystallization technologies. In 2011, CONSOL Energy will also complete construction of pipelines with diffusers to convey high-chloride mine water from the active

Shoemaker Mine and the closed Windsor Mine and discharge those waters into approved mixing zones in the Ohio River. Finally, at the Bailey Mine in Pennsylvania, CONSOL Energy will start construction in 2011 of a new water handling system that will prevent discharge of water containing high total dissolved solids into area streams.

Although these items primarily impact CONSOL Energy’s coal business, management continues to believe our coal business will be successful in developing economic solutions to address these matters. Our coal business is also expected to continue to generate expanding margins due to:

•

Our low-volatile metallurgical coal business with our Buchanan Mine;

•

Our high-volatile metallurgical coal business, where we are selling Northern Appalachian coal to Asian and Brazilian steelmakers at expanded margins; and

•

Lower thermal coal stockpiles.

We believe that coal will continue to provide the base load of the nation’s energy needs. Through our efforts during the last 10 years to improve our operating efficiencies at our major coal production sites, we believe we are well positioned to continue to provide our customers with low cost, high-British thermal units (btus) coal that we expect will generate returns to our shareholders.

Finally, CONSOL Energy is managing several other significant matters that will affect our business in the future:

•

The United Mine Workers’ of America (UMWA) collective bargaining agreement expires on December 31, 2011. Results of future agreements could have a significant effect on future cash flows and earnings of CONSOL Energy. If a new collective bargaining agreement is not reached, CONSOL Energy could be impacted by work stoppages, which would impact our future coal production.

•

Consolidation of CONSOL Energy’s customer base continues to occur. These consolidations may impact the creditworthiness of our customers, the amount of coal or gas a customer buys in a given year, and the terms of new sales contracts.

•

Health care reform legislation included a revision to coal workers’ pneumoconiosis (CWP) regulations which will enable claimants to more easily qualify for a benefit. The legislation also allows for a five-year look back on claims to determine if a previously denied claim will now become eligible. The new legislation impacted CONSOL Energy’s CWP liability by approximately $46 million, as described more fully in Note 16—Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.

•

CONSOL Energy continues to evaluate the potential sale of certain Central Appalachia metallurgical coal properties as well as other non-core assets. To date, there are no definitive agreements in place and evaluation of proposals continue.

Results of Operations

Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $347 million, or $1.60 per diluted share, for the year ended December 31, 2010. Net income attributable to CONSOL Energy shareholders was $540 million, or $2.95 per diluted share, for the year ended December 31, 2009. See below for a detailed explanation by segment of the variance incurred in the period-to-period comparison.

The total coal segment includes steam coal, high volatile metallurgical coal, low volatile metallurgical coal and other coal. The total coal segment contributed $536 million of earnings before income tax for the year ended December 31, 2010 compared to $546 million for the year ended December 31, 2009. The total coal segment sold 63.0 million tons of coal produced from CONSOL Energy mines, excluding our portion of tons sold from equity affiliates, in the year ended December 31, 2010 compared to 57.4 million tons in the year ended December 31, 2009. The average sales price and total costs per ton for all active coal operations were as follows:


	Year Ended December 31,
	2010		2009		Variance		Percent Change
Average Sales Price per ton sold	$	61.33	$	58.70	$	2.63		4.5	%
Average Costs per ton sold		45.44		43.13		2.31		5.4	%

Margin	$	15.89	$	15.57	$	0.32		2.1	%

The higher average sales price per ton sold reflects an additional 2.3 million tons of low volatile metallurgical coal and 2.4 million tons of high volatile metallurgical coal sold in 2010 compared to 2009. The low volatile metallurgical coal segment also had a higher average sales price in 2010 compared to 2009 reflecting the strengthening of the global steel market and steel related products. The high volatile metallurgical coal global market has allowed approximately 2.4 million tons of coal to be sold as a metallurgical product at an average sales price of $72.89 per ton. This coal historically would have been sold on the steam market where our average price for 2010 was $53.76 per ton.

Average costs per ton of coal sold have increased in the period-to-period comparison due primarily to additional labor, higher supply and maintenance costs, and increased other costs which are directly related to the higher sales prices received for tons sold. Additional labor costs per ton are related to the net addition of approximately 330 employees. The additional labor was attributed to the Shoemaker Mine resuming production in 2010 after being idled throughout 2009 to complete the replacement of the track haulage system to a more efficient belt haulage system. Additional labor was also added in order to run our mines more safely, to prepare for the expected retirement of a significant portion of our work force over the next five years, and to keep the development of the longwall panels ahead of longwall advancement. Additional supply costs were attributable to compliance with new safety regulations such as fire retardant belts, additional equipment maintenance and various changes in roof control measures. Costs directly related to the price received for coal sales have also increased. These costs include royalty expenses and various production taxes.

The total gas segment includes coalbed methane (CBM), conventional, Marcellus and other gas. The total gas segment contributed $180 million of earnings before income tax for the year ended December 31, 2010 compared to $263 million for the year ended December 31, 2009. Total gas production was 127.9 billion cubic feet for the year ended December 31, 2010 compared to 94.4 billion cubic feet for the year ended December 31, 2009.

The average sales price and total costs for all active gas operations were as follows:


	Year Ended December 31,
	2010		2009		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	5.83	$	6.68	$	(0.85	)		(12.7	)%
Average Costs per thousand cubic feet sold		3.90		3.44		0.46			13.4	%

Margin	$	1.93	$	3.24	$	(1.31	)		(40.4	)%

Total gas segment outside sales revenues were $746 million for the year ended December 31, 2010 compared to $630 million for the year ended December 31, 2009. The increase was primarily due to the 35.5%

increase in volumes sold, offset, in part, by the 12.7% reduction in average price per thousand cubic feet sold. The decrease in average sales price is the result of various gas swap transactions that occurred throughout both periods. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 52.1 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2010 at an average price of $7.66 per thousand cubic feet. 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. Average gas sales prices excluding the impact of hedging were up slightly in the period-to-period comparison.

Total gas unit costs increased for the year ended December 31, 2010 compared to the year ended December 31, 2009 primarily due to the impact of the higher cost structure of the producing wells purchased in the Dominion Acquisition. These wells increased total operating costs by $0.78 per thousand cubic feet due to the higher maintenance costs, higher gathering and transportation costs and lower volumes produced compared to the legacy CONSOL Energy wells. Excluding the impact of these purchased wells, unit costs improved $0.32 per thousand cubic feet primarily due to the additional volumes produced. Volumes increased in the period-to-period comparison due to the on-going drilling program and the additional volumes from the wells purchased in the Dominion Acquisition.

The other segment includes industrial supplies activity, terminal and river service activity, income taxes and other business activities not assigned to the coal or gas segment.

TOTAL COAL SEGMENT ANALYSIS for the year ended December 31, 2010 compared to the year ended December 31, 2009:

The coal segment contributed $536 million of earnings before income tax in the year ended December 31, 2010 compared to $546 million in the year ended December 31, 2009. Variances by the individual coal segments are discussed below.


	For the Year Ended December 31, 2010											Difference to Year Ended December 31, 2009
	Steam Coal		High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal		Steam Coal			High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal
Sales:
Produced Coal	$	3,001	$	172	$	680	$	12		$	3,865	$	(121	)	$	172	$	431	$	12		$	494
Purchased Coal		—		—		—		34			34		—			—		—		(5	)		(5	)

Total Outside Sales		3,001		172		680		46			3,899		(121	)		172		431		7			489
Freight Revenue		—		—		—		126			126		—			—		—		(23	)		(23	)
Other Income		8		7		—		48			63		1			7		—		(22	)		(14	)

Total Revenue and Other Income		3,009		179		680		220			4,088		(120	)		179		431		(38	)		452
Costs and Expenses:
Total operating costs		1,850		69		232		294			2,445		110			69		116		(10	)		285
Total provisions		198		7		27		129			361		18			7		11		101			137
Total administrative & other costs		142		5		18		97			262		(2	)		5		8		(2	)		9
Depreciation, depletion and amortization		274		11		21		52			358		16			11		8		19			54

Total Costs and Expenses		2,464		92		298		572			3,426		142			92		143		108			485
Freight Expense		—		—		—		126			126		—			—		—		(23	)		(23	)

Total Cost		2,464		92		298		698			3,552		142			92		143		85			462

Earnings (Loss) Before Income Taxes	$	545	$	87	$	382	$	(478	)	$	536	$	(262	)	$	87	$	288	$	(123	)	$	(10	)

STEAM COAL SEGMENT:

The steam coal segment contributed $545 million to total company earnings before income tax in the year ended December 31, 2010 compared to $807 million in the year ended December 31, 2009. The Steam coal revenue and cost components on a per unit basis are as follows:


	2010		2009		Variance			Percent Change
Produced Steam Tons Sold (in millions)		55.8		55.1		0.7			1.3	%
Average Sales Price Per Steam Ton Sold	$	53.76	$	56.64	$	(2.88	)		(5.1	)%
Average Operating Costs Per Steam Ton Sold	$	33.14	$	31.57	$	1.57			5.0	%
Average Provision Costs Per Steam Ton Sold	$	3.55	$	3.27	$	0.28			8.6	%
Average Selling, Administrative and Other Costs Per Steam Ton Sold	$	2.55	$	2.60	$	(0.05	)		(1.9	)%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold	$	4.90	$	4.68	$	0.22			4.7	%

Total Costs Per Steam Ton Sold	$	44.14	$	42.12	$	2.02			4.8	%

Margin	$	9.62	$	14.52	$	(4.90	)		(33.7	)%

Steam coal revenue was $3,001 million for the year ended December 31, 2010 compared to $3,122 million for the year ended December 31, 2009. The $121 million decrease was attributable to an average sales price reduction of $2.88 per ton partially offset by a 0.7 million increase in tons sold. Steam coal average sales price is lower in the 2010 period compared to the 2009 period as a result of higher average sales price mines, such as Bailey and Enlow Fork, selling coal in the high volatile metallurgical coal market instead of the steam coal market. This impacted the steam coal segment as a result of leaving more tons sold from lower sales price mines. This has negatively impacted the average sales price on the steam coal segment, although total company revenue has improved. Produced steam inventory was 1.9 million tons at December 31, 2010 compared to 2.9 million tons at December 31, 2009. Steam sales tons were higher in the period-to-period comparison primarily due to the Shoemaker Mine restarting production in early 2010 after being idled throughout 2009 to complete the replacement of the track haulage system. Steam sales tons were also higher as the result of the Blacksville #2 Mine being idled for several months in 2009 in order to manage inventory levels in response to the economic crisis experienced. Blacksville #2 Mine has operated throughout 2010. These increases were offset, in part, due to selling 2.4 million tons on the high volatile metallurgical coal market at approximately $19.13 per ton higher average sales price.

Other income attributable to the steam coal segment represents earnings from our equity affiliate that operates a steam coal mine. The equity in earnings of affiliates is insignificant to the total segment activity.

Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income, royalties and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costs related to the steam coal segment were $1,850 million for the year ended December 31, 2010 compared to $1,740 million for the year ended December 31, 2009. Higher operating costs in the period-to-period comparison are due to the $1.57 per ton increase in average unit costs of tons sold and 0.7 million of additional tons sold.

Higher average operating costs per unit for steam coal tons sold are primarily related to the following items:

•

Steam coal unit costs were higher in 2010 as a result of lower cost mines, such as Bailey and Enlow Fork, selling coal in the high volatile metallurgical coal market. This impacted the steam coal segment due to increased tons sold from higher cost mines.

•

Labor costs increased due to the effects of wage increases at the union mines from the current labor contracts. The contracts call for specified hourly wage increases in each year of the contract. Labor costs also increased due to the effects of wage increases at the non-represented mines. Average employee counts also increased approximately 5% at our active mining operations. The additional employees were primarily due to the Shoemaker Mine resuming production in 2010 after being idled during 2009 to complete the replacement of the track haulage system to a more efficient belt haulage system. Additional employees were also added in order to run our mines more safely, to prepare for the expected retirement of a significant portion of our work force over the next five years, and to keep the development of the longwall panels ahead of longwall advancement.

•

Health and retirement costs related to the active hourly work force increased due to higher contributions to the multiemployer 1974 pension trust that are required under the National Bituminous Coal Wage Agreement. The contribution rate increased from $4.25 per hour worked by members of the United Mine Workers Union of America (UMWA) in the year ended December 31, 2009 to $5.00 per hour worked in the year ended December 31, 2010. Contributions to the multiemployer plan are expensed as incurred. Health and Retirement costs have also increased in the period-to-period comparison due to higher medical costs for the active hourly work force.

•

Power costs increased due to higher rates charged by utility companies and increased usage in the period-to-period comparison.

•

Operating costs also increased as a result of the 1.0 million ton decrease in inventory levels.

The increases in average unit costs of steam coal sold were offset, in part, by the following:

•

Reduced contract mining fees due to fewer contractors being retained to mine our reserves in the year ended December 31, 2010 compared to the 2009 period.

•

Average operating costs per steam ton sold decreased due to higher tons sold. Fixed costs are allocated over higher tons resulting in decreased unit costs.

Total CONSOL Energy expenses related to our actuarial liabilities were $287 million for the year ended December 31, 2010 compared to $243 million for the year ended December 31, 2009. The increase of $44 million was due primarily to changes in the discount rates used at the measurement date, which is December 31, and changes in assumptions which affect the amount of actuarial gains and losses amortized into earnings. See Note 15—Pension and Other Postretirement Benefits Plans and Note 16—Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional detail regarding total company expense.

Total provisions are made up of the expenses related to the Company’s long-term liabilities, such as other post employment benefits (OPEB), the salary retirement plan, workers’ compensation, long-term disability and accretion expense on mine closing and related liabilities. With the exception of accretion expense on mine closing and related liabilities, these expenses are actuarially calculated for the company as a whole. The expenses are then allocated to operational units based on active employee counts or active salary dollars. Accretion is calculated on a mine-by-mine basis. Provisions attributable to the steam coal segment were $198 million for the year ended December 31, 2010 compared to $180 million for the year ended December 31, 2009. Provision costs per steam coal ton sold increased $0.28 per ton in the period-to-period comparison due primarily to higher actuarial expenses, such as OPEB, as discussed above. The overall increase in company costs has increased the total dollars allocated to the steam coal segment. This increase was offset, in part, by additional tons sold by the steam coal segment.

Total Company Selling, General and Administrative Expenses were made up of the following items:


	2010		2009		Variance		Percent Change
Employee wages and related expenses	$	72	$	63	$	9		14.3	%
Commissions		12		7		5		71.4	%
Miscellaneous		66		61		5		8.2	%

Total Company Selling, General and Administrative Expenses	$	150	$	131	$	19		14.5	%

Employee wages and related expenses have increased due to additional employees in the selling, general and administrative area primarily related to support staff retained in the Dominion Acquisition and additional hiring to support operations. Increased employee wages and related expenses are also related to additional actuarial expenses discussed above.

Commission expenses increased $5 million due to additional tons for which a third party was owed a commission compared to the prior year period.

Miscellaneous expenses have increased approximately $5 million. The increase was related to an additional $2 million for advertising and promotion fees, an additional $2 million for demurrage charges and an additional $1 million for various other items, none of which were individually material.

Total administrative and other costs related to the steam coal segment were $142 million for the year ended December 31, 2010 and $144 million for the year ended December 31, 2009. Selling, general and administrative costs, excluding selling expense, are allocated to all segments based on a combination of estimated time worked by various support groups and operating costs incurred by the individual segments. Commission expense, which is a component of selling, is charged directly to the mine incurring the cost. Direct

administrative costs are associated directly with the coal segment of the business and are allocated to various mines based on a combination of estimated time worked and production. Although the total company selling, general and administrative costs have increased, as discussed above, the amount allocated to the steam coal segment has decreased approximately $2 million. The decrease in the amount allocated to the steam coal segment is primarily related to the high volatile metallurgical coal segment. In 2009, these tons and the associated allocation were all included in the steam coal segment.

Depreciation, depletion and amortization costs for the steam coal segment were $274 million for the year ended December 31, 2010 and $258 million for the year ended December 31, 2009. The increase of $16 million, or $0.22 per ton, was due to additional equipment and infrastructure placed into service after 2009, offset, in part, by additional volumes sold.

HIGH VOL METALLURGICAL COAL SEGMENT:

The high volatile metallurgical coal segment contributed $87 million to total company earnings before income tax for the year ended December 31, 2010. There was no activity in this segment in the prior year. This is a new market that has developed in 2010 and is primarily related to selling our Pittsburgh #8 coal into overseas metallurgical coal markets. This coal had historically supplied the domestic steam coal market. The high volatile metallurgical coal revenue and cost components on a per unit basis are as follows:


	2010		2009		Variance		Percent Change
Produced High Vol Met Tons Sold (in millions)		2.4		—		2.4		100.0	%
Average Sales Price Per High Vol Met Ton Sold	$	72.89	$	—	$	72.89		100.0	%
Average Operating Costs Per High Vol Met Ton Sold	$	29.16	$	—	$	29.16		100.0	%
Average Provision Costs Per High Vol Met Ton Sold	$	3.08	$	—	$	3.08		100.0	%
Average Selling, Administrative and Other Costs Per High Vol Met Ton Sold	$	2.26	$	—	$	2.26		100.0	%
Average Depreciation, Depletion and Amortization Costs Per High Vol Met Ton Sold	$	4.61	$	—	$	4.61		100.0	%

Total Costs per High Vol Met Ton Sold	$	39.11	$	—	$	39.11		100.0	%

Margin	$	33.78	$	—	$	33.78		100.0	%

The high volatile metallurgical coal segment revenue was $172 million, or an average sales price per ton of $72.89, for the year ended December 31, 2010. Strength in the metallurgical coal market has allowed for the export of Northern Appalachian coal, historically sold domestically on the steam coal market, to crossover to the metallurgical coal markets in Brazil and Asia. Total costs per ton sold of this coal were $39.11 generating a margin of $33.78 per ton sold. This margin exceeds the $9.62 per ton average margin received on steam coal sold in 2010 which is where this coal would have been historically sold.

Other income attributable to the high volatile metallurgical coal segment represents earnings from our equity affiliates that operate mines that sell coal on the high volatile metallurgical coal market. The equity in earnings of affiliates is insignificant to the total segment activity.

LOW VOL METALLURGICAL COAL SEGMENT:

The low volatile metallurgical coal segment contributed $382 million to total company earnings before income tax for the year ended December 31, 2010 compared to $94 million for the year ended December 31, 2009. The increase was due primarily to the Buchanan Mine being idled for approximately five months of 2009. The mine was idled in 2009 in response to the economic crisis which significantly lowered the demand for low volatile metallurgical coal, primarily due to the decrease in steel demand. The Buchanan Mine has operated throughout all of 2010. The low volatile metallurgical coal revenue and cost components on a per unit basis are as follows:


	2010		2009		Variance			Percent Change
Produced Low Vol Met Tons Sold (in millions)		4.6		2.3		2.3			100.0	%
Average Sales Price Per Low Vol Met Ton Sold	$	146.32	$	107.72	$	38.60			35.8	%
Average Operating Costs Per Low Vol Met Ton Sold	$	49.82	$	50.31	$	(0.49	)		(1.0	)%
Average Provision Costs Per Low Vol Met Ton Sold	$	5.90	$	6.76	$	(0.86	)		(12.7	)%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold	$	3.95	$	4.57	$	(0.62	)		(13.6	)%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold	$	4.57	$	5.46	$	(0.89	)		(16.3	)%

Total Costs Per Low Vol Met Ton Sold	$	64.24	$	67.10	$	(2.86	)		(4.3	)%

Margin	$	82.08	$	40.62	$	41.46			102.1	%

Average sales price for low volatile metallurgical coal has increased $38.60 per ton, from the prior year, to $146.32 for the year ended December 31, 2010. The increase of 35.8% is mainly due to the strengthening of the global market for steel and steel related products when compared to 2009.

Total costs per ton sold of low volatile metallurgical coal were $64.24 per ton for the year ended December 31, 2010 compared to $67.10 per ton for the year ended December 31, 2009. The $2.86 per ton improvement was related to operating the Buchanan Mine for all of 2010 versus seven months of 2009. The additional tonnage sold in 2010 has reduced the average per unit costs.

OTHER COAL SEGMENT:

The Other Coal segment had a loss before income tax of $478 million for the year ended December 31, 2010 compared to a loss before income tax of $355 million for the year ended December 31, 2009. The Other Coal segment includes purchased coal activities, idled mine activities as well as various other activities assigned to the coal segment but not allocated to each individual mine.

Other Coal segment produced coal sales revenue was $12 million for the year ended December 31, 2010. This revenue includes the sale of incidental tonnage recovered during the reclamation process at idled facilities. The primary focus of activity at these locations is reclaiming disturbed land in accordance with permit requirements after final mining has occurred. The tons sold from these activities are incidental to total company production and sales.

Purchased coal sales were $34 million for the year ended December 31, 2010 compared to $39 million for the year ended December 31, 2009. 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 for a fee.

the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is offset in freight expense. Freight revenue was $126 million in the year ended December 31, 2010 compared to $149 million for the year ended December 31, 2009. The decrease of $23 million was primarily due to lower tons being shipped on CONSOL Energy freight contracts in the period-to-period comparison.

Miscellaneous other income was $48 million for the year ended December 31, 2010 compared to $70 million for the year ended December 31, 2009. The $22 million decrease was due to the following items:

•

In the year ended December 31, 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 be released from the requirements of taking delivery of previously committed tons. No such transactions were entered into in the year ended December 31, 2010.

•

Gain on sales of assets attributable to the Other Coal segment were $9 million for the year ended December 31, 2010 compared to $16 million for the year ended December 31, 2009. The change was related to various transactions that occurred throughout both periods, none of which were individually material.

•

Coal royalty income from third parties was $15 million for the year ended December 31, 2010 compared to $17 million for the year ended December 31, 2009. The decrease was related to lower tons mined by third parties from our coal reserves in the period-to-period comparison.

•

In the year ended December 31, 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 the losses was primarily due to the decrease in market price of coal in 2009 compared to 2008. No such transactions existed in the year ended December 31, 2010.

•

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

Other coal segment total costs were $698 million for the year ended December 31, 2010 compared to $613 million for the year ended December 31, 2009. The increase of $85 million was due to the following items:

•

Closed and idle mine costs increased approximately $77 million for the year ended December 31, 2010 to $215 million from $138 million for the year ended December 31, 2009. The increase in closed and idle mine costs was primarily related to additional reclamation liabilities recognized at the Fola mining operation in West Virginia. As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mine plans, the reclamation liability associated with the Fola operation increased approximately $81 million. Additional closed and idle mine costs in 2010 were also related to a $14 million charge as a result of a change in the mine plan at Mine 84. As a result of the mine plan change, a portion of the previously developed area of the mine has been abandoned. These increases were offset, in part, by approximately $18 million for changes in the operational status of various other mines, between idled and operating, throughout both periods which resulted in lower idled mine costs in 2010. Shoemaker Mine was idled throughout 2009 while the track haulage system was converted to a belt haulage system. This mine was in production throughout 2010.

•

Litigation expense of $25 million was recognized for the year ended December 31, 2010 related to a settlement that was reached in June 2010. The litigation was related to water discharge from our Buchanan Mine being stored in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries.

•

Cost of goods sold and other charges have increased approximately $13 million related to excess purchase price over appraised values for various land purchases that have been made throughout the year. Accounting guidance requires assets purchased to be recognized at the appraised value; synergies

and related specific value to CONSOL Energy cannot be reflected as an asset. Various land deals in strategic areas for items such as refuse ponds, overland belts and various other key projects often require premiums over fair value, thus resulting in additional expense to CONSOL Energy at the time of the transaction.

•

Litigation settlement expense of $11 million was recognized for the year ended December 31, 2010 related to the sale of the Jones Fork Mining Complex.

•

Cost of goods sold and other charges have increased approximately $8 million due to various asset abandonments throughout the period, none of which were individually material. These abandonments primarily related to engineering work, permitting work and mapping work for miscellaneous projects that are no longer being pursued by the Company.

•

Purchased coal 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. These costs were $40 million for the year ended December 31, 2010 compared to $46 million for the year ended December 31, 2009. The decrease of $6 million was primarily due to reduced purchased coal volumes in the period-to-period comparison.

•

Litigation expense of $17 million was recognized for the year ended December 31, 2009 related to amounts accrued for the settlement of the Levisa Action and the Pobst/Combs Action. This litigation related to depositing water in mine voids which a subsidiary of CONSOL Energy leased.

•

Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e. rail, barge, truck, etc.) used by the customers to which CONSOL Energy contractually provides transportation services. Freight expense is offset in freight revenue. Freight expense was $126 million in the year ended December 31, 2010 compared to $149 million for the year ended December 31, 2009. The decrease of $23 million was primarily due to fewer tons shipped on CONSOL Energy freight contracts in the period-to-period comparison.

•

Other costs have decreased $3 million primarily due to various contingent liabilities related to potential legal settlements as well as various other transactions that have occurred throughout both periods, none of which are individually material.

TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2010 compared to the year ended December 31, 2009:

The gas segment contributed $180 million to earnings before income tax for the year ended December 31, 2010 compared to $263 million for the year ended December 31, 2009. Variances by the individual gas segments are discussed below.


	For the Year Ended December 31, 2010													Difference to Year Ended December 31, 2009
	CBM		Conven- tional			Marcellus		Other Gas			Total Gas			CBM			Conven- tional			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	567	$	116		$	48	$	9		$	740		$	(27	)	$	108		$	27	$	5		$	113
Related Party		6		—			—		—			6			3			—			—		—			3

Total Outside Sales		573		116			48		9			746			(24	)		108			27		5			116
Gas Royalty Interest		—		—			—		63			63			—			—			—		22			22
Purchased Gas		—		—			—		11			11			—			—			—		4			4
Other Income		—		—			—		5			5			—			—			—		—			—

Total Revenue and Other Income		573		116			48		88			825			(24	)		108			27		31			142
Lifting		50		30			5		2			87			1			26			4		1			32
Gathering		97		18			10		3			128			9			17			5		1			32
General & Administration		65		22			8		(2	)		93			3			21			4		(2	)		26
Depreciation, Depletion and Amortization		113		50			20		7			190			19			46			13		5			83
Gas Royalty Interest		—		—			—		54			54			—			—			—		22			22
Purchased Gas		—		—			—		10			10			—			—			—		4			4
Exploration and Other Costs		—		—			—		25			25			—			—			—		8			8
Other Corporate Expenses		—		—			—		56			56			—			—			—		23			23
Interest Expense		—		—			—		7			7			—			—			—		(1	)		(1	)

Total Cost		325		120			43		162			650			32			110			26		61			229

Earnings (Loss) Before Noncontrolling Interest and Income Tax		248		(4	)		5		(74	)		175			(56	)		(2	)		1		(30	)		(87	)

Noncontrolling Interest		—		—			—		(5	)		(5	)		—			—			—		(4	)		(4	)

Earnings (Loss) Before Income Tax	$	248	$	(4	)	$	5	$	(69	)	$	180		$	(56	)	$	(2	)	$	1	$	(26	)	$	(83	)

COALBED METHANE (CBM) GAS SEGMENT:

The CBM segment contributed $248 million to the total company earnings before income tax for the year ended December 31, 2010 compared to $304 million for the year ended December 31, 2009. The CBM segment revenue and cost components on a per unit basis are as follows:


	2010		2009		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		91.4		86.9		4.5			5.2	%
Average CBM sales price per thousand cubic feet sold	$	6.27	$	6.87	$	(0.60	)		(8.7	)%
Average CBM lifting costs per thousand cubic feet sold	$	0.54	$	0.57	$	(0.03	)		(5.3	)%
Average CBM gathering costs per thousand cubic feet sold	$	1.06	$	1.01	$	0.05			5.0	%
Average CBM general & administrative costs per thousand cubic feet sold	$	0.70	$	0.71	$	(0.01	)		(1.4	)%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.24	$	1.08	$	0.16			14.8	%

Total CBM costs per thousand cubic feet sold	$	3.54	$	3.37	$	0.17			5.0	%

Margin	$	2.73	$	3.50	$	(0.77	)		(22.0	)%

CBM sales revenues were $573 million for the year ended December 31, 2010 compared to $597 million for the year ended December 31, 2009. The decrease was primarily due to the 8.7% reduction in average price per thousand cubic feet sold, offset, in part, by the 5.2% increase in volumes sold. The decrease in CBM average sales price is the result of various gas swap transactions at a lower average price as compared to the prior year. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 50.5 billion cubic feet of our produced CBM gas sales volumes for the year ended December 31, 2010 at an average price of $7.73 per thousand cubic feet. These financial hedges represented approximately 51.6 billion cubic feet of our produced CBM gas sales volumes for the year ended December 31, 2009 at an average price of $8.76 per thousand cubic feet. Average gas sales prices excluding the impact of hedging were $4.47 per thousand cubic feet in 2010 compared to $4.13 per thousand cubic feet in 2009. CBM sales volumes increased 4.5 billion cubic feet primarily due to additional wells coming online from our on-going drilling program. We had 3,945 net CBM Wells at December 31, 2010 compared to 3,688 net CBM wells at December 31, 2009. Also, 2009 CBM volumes were lower by approximately 1.2 billion cubic feet of deferrals related to the idling of the Buchanan Mine for approximately five months during 2009.

Total costs for the CBM gas segment were $325 million for the year ended December 31, 2010 compared to $293 million for the year ended December 31, 2009. The $32 million increase in total costs in the period-to-period comparison reflects the 5.0% increase in average unit costs and the 5.2% increase in sales volumes.

CBM lifting costs were $50 million for the year ended December 31, 2010 compared to $49 million for the year ended December 31, 2009. Average CBM lifting costs per unit were $0.54 per thousand cubic feet for 2010 compared to $0.57 per thousand cubic feet for 2009. The improvement in average CBM lifting costs per unit was due to lower salt water disposal costs attributable to recycling the water produced from our wells to be used in hydraulic fracturing of new wells. Previously, fees were incurred to dispose of the salt water produced from our wells. Unit costs were also improved due to higher volumes of CBM gas sold in the period-to-period comparison resulting in fixed costs being spread over additional volumes, lowering the average per unit costs. These improvements were offset, in part, by higher severance taxes. Higher severance taxes were the result of average market price increases, excluding the impact of our hedging program. Severance taxes are also higher as a result of the Buchanan County, Virginia severance tax settlement which changed the deductions allowed in the calculation of severance tax due when the price of gas falls between certain ranges. See Note 24—Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion.

CBM Gathering costs were $97 million for the year ended December 31, 2010 compared to $88 million for the year ended December 31, 2009. Average CBM gathering cost were $1.06 per thousand cubic feet sold for the year ended December 31, 2010 compared to $1.01 per thousand cubic feet sold for the year ended December 31, 2009. Higher average unit costs were related to higher power costs attributable to utility rate increases in the period-to-period comparison as well as increased usage. Higher average unit costs were also attributable to additional in-transit costs related to additional capacity of firm transportation being purchased after 2009 to assure delivery of additional volumes being produced. These cost increases were offset, in part, by the 5.2% increase in volumes sold.

General and administrative costs attributable to the Total Gas segment have increased $26 million to $93 million for the year ended December 31, 2010 compared to $67 million for the year ended December 31, 2009. The increase was attributable to additional staffing and additional corporate service charges from CONSOL Energy. With the Dominion Acquisition, which closed on April 30, 2010, the majority of the operational support personnel were retained. Total Company general and administrative costs have also increased, as explained previously, which resulted in additional charges being allocated to all segments.

General and administrative costs attributable to the CBM gas segment were $65 million for the year ended December 31, 2010 compared to $62 million for the year ended December 31, 2009. General and administrative expenses attributable to the Total Gas segment are allocated to each individual gas segment based on a

combination of production and employee counts. Although Total Gas general and administrative costs have increased $26 million, as discussed above, the percentage allocated to the CBM segment is lower, on a unit basis, as the result of CBM production volumes to total gas volumes produced being lower primarily due to the Dominion Acquisition.

Depreciation, depletion and amortization attributable to the CBM segment was $113 million for the year ended December 31, 2010 compared to $94 million for the year ended December 31, 2009. There was approximately $87 million, or $0.95 per unit-of-production, of depreciation, depletion and amortization related to CBM gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2010. The unit-of-production portion of depreciation, depletion and amortization was $71 million, or $0.82 per unit-of-production in the year ended December 31, 2009. The CBM unit-of-production rate used to calculate depreciation in the current year is generally calculated using the net book value of assets divided by either proved or proved developed reserves at the previous year end. The in-field drilling program and certain assets acquired in the Dominion Acquisition caused the rate to increase. There was approximately $26 million, or $0.29 per thousand cubic feet of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the year ended December 31, 2010. The straight-line component was $23 million, or $0.26 per thousand cubic feet for the year ended December 31, 2009. The increase was related to additional gathering assets placed in service after 2009, offset, in part, by the increase in volumes in the period-to-period comparison.

CONVENTIONAL SEGMENT:

The conventional segment had a loss before income tax of $4 million for the year ended December 31, 2010 compared to a loss before income tax of $2 million for the year ended December 31, 2009. The conventional segment revenue and cost components on a per unit basis are as follows:


	2010			2009			Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		24.6			1.7			22.9			1,347.1	%
Average Conventional sales price per thousand cubic feet sold	$	4.73		$	4.33		$	0.40			9.2	%
Average Conventional lifting costs per thousand cubic feet sold	$	1.24		$	2.76		$	(1.52	)		(55.1	)%
Average Conventional gathering costs per thousand cubic feet sold	$	0.75		$	0.59		$	0.16			27.1	%
Average Conventional general & administrative costs per thousand cubic feet sold	$	0.88		$	0.46		$	0.42			91.3	%
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet sold	$	2.05		$	2.30		$	(0.25	)		(10.9	)%

Total Conventional costs per thousand cubic feet sold	$	4.92		$	6.11		$	(1.19	)		(19.5	)%

Margin	$	(0.19	)	$	(1.78	)	$	1.59			(89.3	)%

Conventional segment sales revenues were $116 million for the year ended December 31, 2010 compared to $8 million for the year ended December 31, 2009. Conventional sales volumes increased 22.9 billion cubic feet for the year ended December 31, 2010 primarily due to the Dominion Acquisition. Approximately 95% of the acquired producing wells were conventional type wells. There were 8,517 net conventional wells at December 2010 compared to 195 net conventional wells at December 31, 2009. No conventional gas volumes were hedged in 2010 or 2009.

Total costs for the conventional segment were $120 million for the year ended December 31, 2010 compared to $10 million for the year ended December 31, 2009. The increase of $110 million is attributable to additional volumes sold in the period-to-period comparison, offset, in part, by lower average unit costs sold. Conventional average unit costs have decreased due to the significant increase in volumes related to production from wells acquired in the Dominion Acquisition. A detailed analysis of cost categories is not meaningful due to the significant change in this segment related to the Dominion Acquisition and will therefore not be presented.

General and administrative costs attributable to the Total Gas segment are allocated to each individual gas segment based on a combination of production and employee counts. Conventional volumes are higher as a percent of total gas produced volumes in the period-to-period comparison and therefore, additional general and administrative costs have been allocated to the conventional gas segment in 2010.

MARCELLUS SEGMENT:

The Marcellus segment contributed $5 million to the total company earnings before income tax for the year ended December 31, 2010 compared to $4 million for the year ended December 31, 2009. The Marcellus segment revenue and cost components on a per unit basis are as follows:


	2010		2009		Variance			Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		10.2		5.0		5.2			104.0	%
Average Marcellus sales price per thousand cubic feet sold	$	4.68	$	4.24	$	0.44			10.4	%
Average Marcellus lifting costs per thousand cubic feet sold	$	0.48	$	0.12	$	0.36			300.0	%
Average Marcellus gathering costs per thousand cubic feet sold	$	1.01	$	1.12	$	(0.11	)		(9.8	)%
Average Marcellus general & administrative costs per thousand cubic feet sold	$	0.75	$	0.74	$	0.01			1.4	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.93	$	1.47	$	0.46			31.3	%

Total Marcellus costs per thousand cubic feet sold	$	4.17	$	3.45	$	0.72			20.9	%

Margin	$	0.51	$	0.79	$	(0.28	)		(35.4	)%

The increase in Marcellus average sales price was the result of an improvement in general market prices and various gas swap transactions that occurred in the year ended December 31, 2010. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 1.6 billion cubic feet of our produced Marcellus gas sales volumes for the year ended December 31, 2010 at an average price of $5.05 per thousand cubic feet. There were no gas swap transactions for the Marcellus segment that occurred for the year ended December 31, 2009. The increase in sales volumes was primarily due to additional wells coming online from our on-going drilling program. At December 31, 2010 there were 52 Marcellus Shale wells in production including 17 wells acquired in the Dominion Acquisition. At December 31, 2009 there were 22 Marcellus Shale wells in production.

Total costs for the Marcellus segment were $43 million for the year ended December 31, 2010 compared to $17 million for the year ended December 31, 2009. The increase was primarily due to the additional sales volumes and higher average unit costs.

Marcellus lifting costs were $5 million for the year ended December 31, 2010 compared to $1 million for the year ended December 31, 2009. Average Marcellus lifting costs were $0.48 per thousand cubic feet in 2010 compared to $0.12 per thousand cubic feet in 2009. The increase in average lifting costs per unit sold was due to increased road repairs and other maintenance expense primarily related to the additional number of wells drilled in the current period. Salt water disposal fees were also higher in the period-to-period comparison due to the higher volume of water produced from additional wells. These increases in costs were offset, in part, by the additional volume of Marcellus gas sold in the period-to-period comparison.

Marcellus gathering costs were $10 million for the year ended December 31, 2010 compared to $5 million for the year ended December 31, 2009. Average gathering cost per unit sold was $1.01 per thousand cubic feet for the year ended December 31, 2010 compared to $1.12 per thousand cubic feet for the year ended December 31, 2009. Lower average gathering cost per unit was primarily attributable to the 104.0% increase in volumes sold. This improvement was offset, in part, by higher power and security costs. Higher power costs were related to higher rates being charged by utility companies in the period-to-period comparison. Higher security costs were related to additional security needs at various Marcellus gathering stations.

General and administrative costs attributable to the Marcellus gas segment were $8 million for the year ended December 31, 2010 compared to $4 million for the year ended December 31, 2009. Average general and administrative costs on a per unit sold basis were $0.75 per thousand cubic feet for the year ended December 31, 2010 compared to $0.74 per thousand cubic feet for the year ended December 31, 2009. General and administrative costs attributable to the Total Gas segment are allocated to each individual gas segment based on a combination of production and employee counts. The total general and administrative cost increases, as discussed previously, were offset, in part, by higher volumes of gas produced from Marcellus wells.

Depreciation, depletion and amortization attributable to the Marcellus segment was $20 million for the year ended December 31, 2010 compared to $7 million for the year ended December 31, 2009. There was approximately $18 million, or $1.73 per unit-of-production, of depreciation, depletion and amortization related to Marcellus gas and related well equipment that was reflected on a units-of-production method of depreciation in the year ended December 31, 2010. The unit-of-production portion of depreciation, depletion and amortization was $6 million, or $1.27 per unit-of-production in the year ended December 31, 2009. The Marcellus unit-of-production rate used to calculate depreciation in the current year is generally calculated using the net book value of assets divided by either proved or proved developed reserves at the previous year end. The investment in drilling activities increased in higher proportion than the related gas reserves in the current period, which resulted in a higher per unit rate. There was approximately $2 million, or $0.20 per thousand cubic feet of depreciation, depletion and amortization related to gathering and other equipment that is reflected on a straight-line basis for the year ended December 31, 2010. The straight-line component was $1 million, or $0.20 per thousand cubic feet for the year ended December 31, 2009. The increase was related to additional gathering assets placed in service after 2009, offset, in part, by the increase in volumes in the period-to-period comparison.

OTHER GAS SEGMENT:

The Other gas segment includes activity not assigned to CBM, Conventional or Marcellus gas segments. This segment includes purchased gas activity, gas royalty interest activity, exploration and other costs, other corporate expenses, and miscellaneous operational activity not assigned to a specific gas segment. The other gas segment had a loss before income tax of $69 million for the year ended December 31, 2010 compared to a loss before income tax of $43 million for the year ended December 31, 2009.

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $9 million for the year ended December 31, 2010 compared to $4 million for the year ended December 31, 2009. There was 1.7 billion cubic feet sold from this area for the year ended December 31, 2010 compared to 0.8 billion cubic feet for the year ended December 31, 2009. Total costs related to these other sales were $10 million for the year ended December 31, 2010 compared to $5 million for the year ended December 31, 2009. The increase in costs in the period-to-period comparison was primarily due to higher depreciation, depletion and amortization attributable to the additional 0.9 billion cubic feet of gas produced and higher unit-of-production rates. The higher units-of-production rates were related to a higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. A per unit analysis of the other operating costs in Chattanooga is not meaningful due to the low volumes produced in the period-to-period analysis.

Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas sales revenues were $63 million for the year ended December 31, 2010 compared to $41 million for the year ended December 31, 2009.


	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		14.2		9.8		4.4		44.9	%
Average Sales Price Per thousand cubic feet sold	$	4.41	$	4.17	$	0.24		5.8	%

Purchased gas sales volumes represent volumes of gas we sold at market prices that were purchased from third-party producers. Purchased gas sales revenues were $11 million for the year ended December 31, 2010 compared to $7 million for the year ended December 31, 2009.


	2010		2009		Variance		Percent Change
Purchased Gas Sales Volumes (in billion cubic feet)		2.0		1.6		0.4		25.0	%
Average Sales Price Per thousand cubic feet sold	$	5.48	$	4.46	$	1.02		22.9	%

Other income was consistent at $5 million for the years ended December 31, 2010 and 2009.

Royalty interest gas costs represent the costs related to the portion of production belonging to royalty interest owners sold by the CONSOL Energy gas segment. The changes in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the period-to-period change. Royalty interest gas sales costs were $54 million for the year ended December 31, 2010 compared to $32 million for the year ended December 31, 2009.


	2010		2009		Variance		Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		14.2		9.8		4.4		44.9	%
Average Cost Per thousand cubic feet sold	$	3.78	$	3.30	$	0.48		14.5	%

Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes also reflect the impact of pipeline imbalances. The higher average cost per thousand cubic feet is due to overall price changes, contractual differences among customers and the pipeline imbalance. Purchased gas costs were $10 million for the year ended December 31, 2010 compared to $6 million for the year ended December 31, 2009.


	2010		2009		Variance		Percent Change
Purchased Gas Volumes (in billion cubic feet)		1.9		1.7		0.2		11.8	%
Average Cost per thousand cubic feet sold	$	5.14	$	3.75	$	1.39		37.1	%

Exploration and other costs were $25 million for the year ended December 31, 2010 compared to $17 million for the year ended December 31, 2009. The $8 million increase was made up of the following items:


	2010		2009		Variance		Percent Change
Dry hole and lease expiration costs	$	16	$	10	$	6		60.0	%
Land and delay rentals		5		4		1		25.0	%
Exploration		4		3		1		33.3	%

Total Exploration and Other Costs	$	25	$	17	$	8		47.1	%

Dry hole and lease expiration costs were $6 million higher in the period-to-period comparison primarily due to lease surrenders in the current year, offset, in part, by lower dry wells drilled in the year ended December 31, 2010.

Land and delay rentals, as well as Exploration, both increased $1 million in the period-to-period comparison due to various transactions that occurred throughout both periods, none of which were individually material.

Other corporate expenses were $56 million for the year ended December 31, 2010 compared to $33 million for the year ended December 31, 2009. The $23 million increase was due to the following items:


	2010		2009		Variance			Percent Change
Short-term incentive compensation	$	24	$	16	$	8			50.0	%
Stock-based compensation		16		11		5			45.5	%
Variable interest earnings		4		—		4			100.0	%
Bank fees		4		—		4			100.0	%
Financing and acquisition fees		3		—		3			100.0	%
Contract settlement		—		3		(3	)		(100.0	)%
Other		5		3		2			66.7	%

Total Other Corporate Expenses	$	56	$	33	$	23			69.7	%

The short-term incentive compensation program is designed to increase compensation to eligible employees when the gas segment reaches predetermined targets for safety, production and unit cost goals. Short-term incentive compensation expense is higher in 2010 due to a 13% increase in employee counts, as well as an increase in the short-term incentive compensation allocation to the gas segment. Additional employees in the total company general and administrative area were primarily related to support staff retained in the Dominion Acquisition and additional hiring to support operations.

Stock-based compensation is higher in the period-to-period comparison primarily due to the conversion of the CNX Gas performance share units to CONSOL Energy restricted stock units in the year ended December 31, 2009. The conversion resulted in a reduction of approximately $4 million of expense in 2009. Additional expense was also related to stock-based compensation allocated from CONSOL Energy to the gas segment in 2010. These increases were offset, in part, by the non-vested CNX Gas stock options being terminated in relation to the CNX Gas take-in transaction. The expense previously recognized for these options was reversed on the gas segment. All stock-based compensation is now allocated from CONSOL Energy.

Variable interest earnings are related to various adjustments a third party entity has reflected in its financial statements. CONSOL Energy holds no ownership interest, but guarantees bank loans the entity holds related to its purchases of drilling rigs. CONSOL Energy is also the main customer of the third party, and based on analysis is the primary beneficiary. Therefore, the entity is fully consolidated and then the impact is fully reversed in the noncontrolling interest line discussed below.

Banks fees are higher in the period-to-period comparison due to amending and extending the revolving credit facility related to the gas segment.

Financing and acquisition fees are related to legal expenses for the special committee, formed during the CNX Gas take-in transaction, and are primarily related to the shareholder litigation.

The year ended December 31, 2009 includes $3 million of expense related to a contract buyout with a driller in order to mitigate idle rig charges in certain areas where drilling was not expected to increase in the near term.

Other corporate expense increased $2 million in the year-to-year comparison primarily due to unused firm transportation charges not being allocated to the operating gas segments and various other transactions that occurred throughout both periods, none of which were individually material.

Interest expense was $7 million for the year ended December 31, 2010 compared to $8 million for the year ended December 31, 2009. Interest is incurred by the gas segment on the gas segment revolving credit facility, a capital lease and debt held by a variable interest entity. No significant changes in these components occurred in the period-to-period comparison.

Noncontrolling interest represents 100% of the earnings impact of a third party which has been determined to be a variable interest entity, in which the CONSOL Energy gas segment holds no ownership interest, but is the primary beneficiary. The CONSOL Energy gas segment has been determined to be the primary beneficiary due to guarantees of the third party’s bank debt related to their purchase of drilling rigs. The third party entity provides drilling services primarily to the CONSOL Energy gas segment. CONSOL Energy consolidates the entity and then reflects 100% of the impact as noncontrolling interest. The consolidation does not significantly impact any amounts reflected in the gas segment income statement. The variance in the noncontrolling interest amounts reflects the third party’s variance in earnings in the period-to-period comparison.

OTHER SEGMENT ANALYSIS for the year ended December 31, 2010 compared to the year ended December 31, 2009:

The other segment includes activity from sales of industrial supplies, transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $249 million for the year ended December 31, 2010 compared to a loss of $22 million for the year ended December 31, 2009. The other segment also includes total company income tax expense of $109 million for the year ended December 31, 2010 and $221 million for the year ended December 31, 2009.


	2010			2009			Variance			Percent Change
Sales-Outside	$	297		$	273		$	24			8.8	%
Other Income		29			29			—			—

Total Revenue		326			302			24			7.9	%
Cost of Goods Sold and Other Charges		349			267			82			30.7	%
Depreciation, Depletion & Amortization		18			20			(2	)		(10.0	)%
Taxes Other Than Income Tax		10			13			(3	)		(23.1	)%
Interest Expense		198			24			174			725.0	%

Total Costs		575			324			251			77.5	%

Loss Before Income Tax		(249	)		(22	)		(227	)		(1,031.8	)%
Income Tax		109			221			(112	)		(50.7	)%

Net Loss	$	(358	)	$	(243	)	$	(115	)		(47.3	)%

Industrial Supplies:

Total revenues from industrial supply operations were $195 million for the year ended December 31, 2010 compared to $196 million for the year ended December 31, 2009.

Total costs related to industrial supply sales were $197 million for the year ended December 31, 2010 compared to $190 million for the year ended December 31, 2009. The $7 million increase in expense is primarily due to changes in last-in-first-out valuations.

Transportation operations:

Total revenue from transportation operations was $114 million for the year ended December 31, 2010 compared to $84 million for the year ended December 31, 2009. The $30 million increase was primarily attributable to additional through-put tons at the Baltimore terminal in the period-to-period comparison.

Total costs related to transportation operations were $81 million for the year ended December 31, 2010 compared to $70 million for the year ended December 31, 2009. The $11 million increase was primarily related to the additional through-put tons at the Baltimore terminal in the period-to-period comparison.

Miscellaneous Other:

Other income was $17 million for the year ended December 31, 2010 compared to $22 million for the year ended December 31, 2009. The $5 million decrease was attributable to $6 million of Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the Company’s previous headquarters in 2009. This was offset by $1 million related to various transactions that occurred throughout both periods, none of which were individually material.

Other corporate costs include interest cost, acquisition and financing costs and various other miscellaneous corporate charges. Total other costs were $297 million for the year ended December 31, 2010 and $64 million for the year ended December 31, 2009. Other corporate costs increased $233 million due to the following:

•

Interest expense of $198 million was incurred in the year ended December 31, 2010 compared to $24 million in the year ended December 31, 2009. The increase of $174 million was primarily attributable to the additional interest expense on the long-term bonds that were issued in conjunction with the Dominion Acquisition.

•

Financing and acquisition fees of $62 million were incurred in the year ended December 31, 2010 primarily related to the equity and debt issuance that raised approximately $4.6 billion dollars. These fees also include costs related to extending and refinancing the CONSOL Energy revolving credit facility, the Dominion Acquisition and the purchase of the CNX Gas noncontrolling interest.

•

Bank fees of $16 million were incurred in the year ended December 31, 2010 compared to $5 million in the year ended December 31, 2009. The increase of $11 million was primarily related to the refinanced revolving credit facility.

•

Fees related to the disposition of non-core assets of $3 million were incurred in the year ended December 31, 2010.

•

Various other corporate expenses were $21 million in the year ended December 31, 2010 compared to $18 million in the year ended December 31, 2009. The increase of $3 million was due to various transactions that occurred throughout both periods, none of which were individually material.

•

In the year ended December 31, 2010, there was $3 million of reduced expense related to an adjustment to assumptions used in the 2009 cease use of the Company’s previous headquarter liability. The year ended December 31, 2009 included $13 million of expense related to the cease use of the facility. These transactions resulted in a $16 million improvement in the period-to-period comparison.

•

Severance payments of $4 million were incurred in the year ended December 31, 2009 related to various layoffs that were necessary due to the economic downturn that occurred.

Income Taxes:

The effective income tax rate was 23.4% for the year ended December 31, 2010 compared to 28.1% for the year ended December 31, 2009. The effective tax rate is sensitive 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. The mix of pre-tax income by state may also impact the overall effective tax rate. The pre-tax income mix by state has changed in the period-to-period comparison due to the Dominion Acquisition. See Note 6—Income Taxes in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for additional explanation of the effective tax rate change in the period-to-period comparison.


	2010			2009			Variance			Percent Change
Total Company Earnings Before Income Taxes	$	468		$	788		$	(320	)		(40.6	)%
Income Tax Expense	$	109		$	221		$	(112	)		(50.7	)%
Effective Income Tax Rate		23.4	%		28.1	%		(4.7	)%

Results of Operations

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

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $540 million, or $2.95 per diluted share, for the year ended December 31, 2009. Net income attributable to CONSOL Energy shareholders was $442 million, or $2.40 per diluted share, for the year ended December 31, 2008. See below for a detailed explanation by segment of the variance incurred in the period-to-period comparison.

The average sales price and total costs for all active coal operations was as follows:


	Year Ended December 31,
	2009		2008		Variance		Percent Change
Average Sales Price per ton sold	$	58.70	$	47.61	$	11.09		23.3	%
Average Costs per ton sold		43.13		39.36		3.77		9.6	%

Margin	$	15.57	$	8.25	$	7.32		88.7	%

The gas segment includes coalbed methane (CBM), conventional, Marcellus and other gas. The segments are determined based on activities from target strata. The other gas segment includes royalty interest activities, purchased gas activities and other activities assigned to the gas segment, but not allocated to each individual component. Prior to 2009, the gas segment was primarily made up of the CBM segment. Less than one percent of sales volumes were attributable to the conventional and Marcellus operations. Due to the insignificant amounts attributable to the conventional and Marcellus activities, a comparison of these operations will not be discussed.

The average sales price and total costs for all active gas operations was as follows:


	Year Ended December 31,
	2009		2008		Variance			Percent Change
Average Sales Price per thousand cubic feet sold	$	6.68	$	8.99	$	(2.31	)		(25.7	)%
Average Costs per thousand cubic feet sold		3.44		3.66		(0.22	)		(6.0	)%

Margin	$	3.24	$	5.33	$	(2.09	)		(39.2	)%

The other segment includes industrial supplies activity, terminal and river service activity, income taxes and other business activities not assigned to the coal or gas segment.

TOTAL COAL SEGMENT ANALYSIS for the year ended December 31, 2009 compared to the year ended December 31, 2008:

The Total Coal segment contributed $546 million to earnings before income tax for the year ended December 31, 2009 compared to $344 million for the year ended December 31, 2008.


	For the Year Ended December 31, 2009											Difference to Year Ended December 31, 2008
	Steam Coal		High Vol Met Coal		Low Vol Met Coal		Other Coal			Total Coal		Steam Coal			High Vol Met Coal		Low Vol Met Coal			Other Coal			Total Coal
Sales:
Produced Coal	$	3,122	$	—	$	249	$	—		$	3,371	$	399		$	—	$	(92	)	$	—		$	307
Purchased Coal		—		—		—		39			39		—			—		—			(79	)		(79	)

Total Outside Sales		3,122		—		249		39			3,410		399			—		(92	)		(79	)		228
Freight Revenue		—		—		—		149			149		—			—		—			(68	)		(68	)
Other Income		7		—		—		70			77		7			—		—			(51	)		(44	)

Total Revenue and Other Income		3,129		—		249		258			3,636		406			—		(92	)		(198	)		116
Costs and Expenses:
Total operating costs		1,740		—		116		304			2,160		(25	)		—		(21	)		24			(22	)
Total provisions		180		—		16		28			224		(5	)		—		1			(18	)		(22	)
Total administrative & other costs		144		—		10		99			253		(2	)		—		(4	)		27			21
Depreciation, depletion and amortization		258		—		13		33			304		—			—		(1	)		6			5

Total Costs and Expenses		2,322		—		155		464			2,941		(32	)		—		(25	)		39			(18	)
Freight Expense		—		—		—		149			149		—			—		—			(68	)		(68	)

Total Cost		2,322		—		155		613			3,090		(32	)		—		(25	)		(29	)		(86	)

Earnings (Loss) Before Income Taxes	$	807	$	—	$	94	$	(355	)	$	546	$	438		$	—	$	(67	)	$	(169	)	$	202

STEAM COAL SEGMENT:

The steam coal segment contributed $807 million to total company earnings before income tax for the year ended December 31, 2009 compared to $369 million for the year ended December 31, 2008.

Steam coal revenue was $3,122 million for the year ended December 31, 2009 compared to $2,723 million for the year ended December 31, 2008. The increase of $399 million was attributable to the higher average price per ton sold, offset, in part, by lower sales volumes of company produced steam coal sold.


	2009		2008		Variance			Percent Change
Produced Steam Tons Sold (in millions)		55.1		61.4		(6.3	)		(10.3	)%
Average Sales Price Per Steam Ton Sold	$	56.64	$	44.31	$	12.33			27.8	%
Average Operating Costs Per Steam Ton Sold	$	31.57	$	28.70	$	2.87			10.0	%
Average Provision Costs Per Steam Ton Sold	$	3.27	$	3.01	$	0.26			8.6	%
Average Selling, Administrative and Other Costs Per Steam Ton Sold	$	2.60	$	2.38	$	0.22			9.2	%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold	$	4.68	$	4.20	$	0.48			11.4	%

Total Costs Per Steam Ton Sold	$	42.12	$	38.29	$	3.83			10.0	%

Margin	$	14.52	$	6.02	$	8.50			141.2	%

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 steam coal shipments decreased in 2009 due to delivery deferments of Central and Northern Appalachian coals. Coal consumption by the electric power sector continued to decline during 2009.

Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income, royalties and preparation plant charges related to the extraction and sale of coal. These costs are reviewed regularly by management and are considered to be the direct responsibility of mine management. Operating costs related to the steam coal segment were $1,740 million for the year ended December 31, 2009 compared to $1,765 million for the year ended December 31, 2008.

Higher average operating costs per unit for steam coal tons sold is primarily related to the following items:

•

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

•

Supply costs per unit are higher in 2009 due 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 due to the effects of wage increases at the union and non-represented 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.

•

Production taxes per steam ton sold increased due to higher average sales prices received for this coal.

•

United Mine Workers of America (UMWA) health and retirement plan expenses increased over 2008 primarily due to the effects of the 2007 labor contract that requires additional contributions to be made into employee benefit funds. The contribution increase over 2008 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 costs increased 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.

Total provisions are made up of the expenses related to the company’s long-term liabilities such as other post employment benefits (OPEB), the salary retirement plan, workers’ compensation, long term disability and mine closing and related liabilities. With the exception of mine closing and related liabilities accretion expense, these liabilities are actuarially calculated for the company as a whole. The expenses associated with these costs are allocated to operational units based on active employee counts or active salary labor dollars. Mine closing and related liabilities accretion is calculated on a mine-by-mine basis. The provision expense attributable to the steam coal segment was $180 million for the year ended December 31, 2009 compared to $185 million for the year ended December 31, 2008.

Total CONSOL Energy expenses related to our actuarial liabilities were $243 million for the years ended December 31, 2009 and 2008. Provision costs per unit of steam tons sold increased in the period-to-period comparison due primarily to lower tons sold.

Total Company Selling, General and Administrative Expenses:


	2009		2008		Variance			Percent Change
Rentals	$	9	$	3	$	6			200.0	%
Employee wages and related expenses		63		61		2			3.3	%
Miscellaneous		59		61		(2	)		(3.3	)%

Total Company Selling, General and Administrative Expenses	$	131	$	125	$	6			4.8	%

Total company selling, general and administrative costs were $131 million for the year ended December 31, 2009 compared to $125 million for the year ended December 31, 2008. The $6 million increase was due to the following items:

•

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.

•

Other selling, general and administrative costs decreased $2 million due to various transactions throughout both periods, none of which are individually material.

Total administrative and other costs include selling expenses, general and administrative expenses and direct administrative costs. Selling, general and administrative costs, excluding commission expense, are allocated to the mines on a combination of estimated time worked by various support groups and operating costs incurred at the mine. Commission expense, which is a component of selling expense, is charged directly to the mine incurring the cost. Direct administrative costs are associated directly with the coal segment of the business and are allocated to various mines based on a combination of estimated time worked and production. Total administrative and other costs related to the steam coal segment were $144 million for the year ended December 31, 2009 compared to $146 million for the year ended December 31, 2008. Average selling, general and administrative costs per unit have increased due to lower steam tons sold in the period-to-period comparison and higher total company expense as discussed below.

Depreciation, depletion and amortization for the steam coal segment was $258 million for both of the years ended December 31, 2009 and 2008. Average depreciation, depletion and amortization unit costs increased $0.48 per ton due to lower tons sold in the period-to-period comparison.

LOW VOLATILE METALLURGICAL COAL SEGMENT:

The low volatile metallurgical coal segment contributed $94 million to total company earnings before income tax for the year ended December 31, 2009 compared to $161 million for the year ended December 31, 2008.

Low volatile metallurgical coal revenue was $249 million for the year ended December 31, 2009 compared to $341 million for the year ended December 31, 2008. The decrease of $92 million was due to the lower average price per ton sold and lower sales volumes of company produced low volatile metallurgical coal sold.


	2009		2008		Variance			Percent Change
Produced Low Vol Met Tons Sold (in millions)		2.3		2.9		(0.6	)		(20.7	)%
Average Sales Price Per Low Vol Met Ton Sold	$	107.72	$	117.48	$	(9.76	)		(8.3	)%
Average Operating Costs Per Low Vol Met Ton Sold	$	50.31	$	47.17	$	3.14			6.7	%
Average Provision Costs Per Low Vol Met Ton Sold	$	6.76	$	5.31	$	1.45			27.3	%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold	$	4.57	$	4.71	$	(0.14	)		(3.0	)%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold	$	5.46	$	4.75	$	0.71			14.9	%

Total Costs Per Low Vol Met Ton Sold	$	67.10	$	61.94	$	5.16			8.3	%

Margin	$	40.62	$	55.54	$	(14.92	)		(26.9	)%

The decrease in average sales price for low volatile 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 low volatile metallurgical coal decreased in 2009 due to a downturn in the domestic and international steel business resulting in reduced demand for low volatile metallurgical coal and the idling of the Buchanan mine from March 1, 2009 to August 7, 2009.

Total costs for the low volatile metallurgical coal segment were $155 million for the year ended December 31, 2009 compared to $180 million for the year ended December 31, 2008. A meaningful comparison of unit costs cannot be made because of the low volume of coal produced and sold from the low volatile metallurgical coal segment in 2009, as discussed above. The impairments in unit costs were related to idling the Buchanan mine from March 1, 2009 to August 7, 2009. The 2009 unit costs are not representative of the operating mine due to fixed costs being spread over significantly fewer tons.

OTHER COAL SEGMENT:

The Other Coal segment had a loss before tax of $355 million for the year ended December 31, 2009 compared to a loss before income tax $186 for the year ended December 31, 2008. The Other Coal segment includes purchased coal activities, closed and idle mine costs, and miscellaneous transactions that are directly related to the coal segment.

Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specification, coal purchased from third parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants. The revenues were $39 million for the year ended December 31, 2009 and $118 million in the year ended December 31, 2008. The decrease of $79 million in purchased coal revenue was primarily due to a decrease in demand in the year-to-year comparisons.

Freight revenue is the amount billed to customers for transportation costs incurred. This 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 has decreased $68 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 on the cost to the customer.

Miscellaneous other income was $70 million for the year ended December 31, 2009 compared to $121 million for the year ended December 31, 2008. The $51 million decrease consisted of the following items:

•

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.

•

Other miscellaneous income decreased $13 million in the year-to-year comparison due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

These decreases were partially offset by the following item:

•

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. No such transactions occurred in 2008.

Other coal segment total costs were $613 million for the year ended December 31, 2009 compared to $642 million for the year ended December 31, 2008. The decrease of $29 million was due to the following items:

•

Purchased coal costs decreased $79 million in the year-to-year comparison. Purchased coal costs consist of expenses from processing third-party coal in our preparation plants for blending purposes to meet customer coal specification, cost of coal purchased from third parties and sold directly to our customers and costs related to processing third-party coal in our preparation plants.

•

Freight expense decreased $68 million 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 has decreased 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 expense also decreased due to fewer export sales made to customers whom CONSOL Energy pays the ocean-going freight and then passes on the cost to the customer.

•

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, $21 million of costs related to the Buchanan Mine event were incurred.

•

The year ended December 31, 2008 included 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 included fewer customer buyouts. The costs for these transactions were $2 million in 2009 compared to $19 million in 2008.

•

In the year ended December 31, 2008, $15 million of expense was recognized 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.

•

Incentive compensation and stock-based compensation expense increased $14 million as a result of the Company reaching pre-determined targets for production, safety and unit costs and additional awards granted.

•

Royalty expense increased $16 million in the year-to-year comparison as a result of increased average sales prices and increased volumes mined on leased tracts.

•

Other coal segment costs increased $17 million in 2009 related to litigation expense recognized in conjunction with the Levisa Action and the Pobst/Combs Action. This litigation related to depositing water in mine voids of adjacent properties which were leased by CONSOL Energy subsidiaries.

•

Other miscellaneous costs increased $21 million in the year-to-year comparison due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

•

Closed and idle mine total costs increased $48 million in the year-to-year comparison. Approximately $38 million of increased expenses were incurred at Mine 84 to remove underground equipment from 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 $12 million of additional expenses in 2009 related to the continued maintenance of the mine in an idled status. Closed and idle mine total costs also increased $17 million primarily due to changes in the operational status of various other mines between idled and operating, throughout both periods which resulted in higher idled mine costs 2009. These increases were offset, in part, by reductions of $19 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.

•

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 ESSA 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 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.

TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2009 compared to the year ended December 31, 2008:

The Total Gas segment contributed $263 million to earnings before income tax for the year ended December 31, 2009 compared to $386 million for the year ended December 31, 2008. In the year ended December 31, 2008, approximately 99% of our gas sales volumes were attributable to coalbed methane (CBM). The revenues and costs associated with Conventional and Marcellus production were insignificant, thus a comparison has not been presented. All comparisons and explanations are related to the CBM and Other gas segment.


	For the Year Ended December 31, 2009													Difference to Year Ended December 31, 2008
	CBM		Conven- tional			Marcellus		Other Gas			Total Gas			CBM			Conven- tional			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	594	$	8		$	21	$	4		$	627		$	(85	)	$	8		$	21	$	4		$	(52	)
Related Party		3		—			—		—			3			1			—			—		—			1

Total Outside Sales		597		8			21		4			630			(84	)		8			21		4			(51	)
Gas Royalty Interest		—		—			—		41			41			—			—			—		(38	)		(38	)
Purchased Gas		—		—			—		7			7			—			—			—		(2	)		(2	)
Other Income		—		—			—		5			5			—			—			—		(8	)		(8	)

Total Revenue and Other Income		597		8			21		57			683			(84	)		8			21		(44	)		(99	)
Lifting		49		4			1		1			55			(19	)		4			1		1			(13	)
Gathering		88		1			5		2			96			4			1			5		2			12
General & Administration		62		1			4		—			67			4			1			4		—			9
Depreciation, Depletion and Amortization		94		4			7		2			107			24			4			7		2			37
Gas Royalty Interest		—		—			—		32			32			—			—			—		(43	)		(43	)
Purchased Gas		—		—			—		6			6			—			—			—		(2	)		(2	)
Exploration and Other Costs		—		—			—		17			17			—			—			—		13			13
Other Corporate Expenses		—		—			—		33			33			—			—			—		12			12
Interest Expense		—		—			—		8			8			—			—			—		—			—

Total Cost		293		10			17		101			421			13			10			17		(15	)		25

Earnings (Loss) Before Noncontrolling Interest and Income Tax		304		(2	)		4		(44	)		262			(97	)		(2	)		4		(29	)		(124	)

Noncontrolling Interest		—		—			—		(1	)		(1	)		—			—			—		(1	)		(1	)

Earnings (Loss) Before Income Tax	$	304	$	(2	)	$	4	$	(43	)	$	263		$	(97	)	$	(2	)	$	4	$	(28	)	$	(123	)

COALBED METHANE (CBM) GAS SEGMENT:

The CBM segment contributed $304 million to the total company earnings before income tax for the year ended December 31, 2009 compared to $401 million for the year ended December 31, 2008. The decrease is due to the following items.

CBM sales revenues decreased $84 million in the year-to-year comparison. The decrease in outside sales was primarily due to lower average sales prices received, offset, in part, by higher volumes of gas sold.


	2009		2008		Variance			Percent Change
Produced gas CBM sales volumes (in billion cubic feet)		86.9		75.7		11.2			14.8	%
Average CBM sales price per thousand cubic feet sold	$	6.87	$	9.00	$	(2.13	)		(23.7	)%
Average CBM lifting costs per thousand cubic feet sold	$	0.57	$	0.89	$	(0.32	)		(36.0	)%
Average CBM gathering costs per thousand cubic feet sold	$	1.01	$	1.11	$	(0.10	)		(9.0	)%
Average CBM general & administrative costs per thousand cubic feet sold	$	0.71	$	0.78	$	(0.07	)		(9.0	)%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.08	$	0.92	$	0.16			17.4	%

Total CBM costs per thousand cubic feet sold	$	3.37	$	3.70	$	(0.33	)		(8.9	)%

Margin	$	3.50	$	5.30	$	(1.80	)		(34.0	)%

Sales volumes increased as a result of additional wells coming online from our ongoing 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 CONSOL Energy. 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.

CBM lifting costs were $49 million for the year ended December 31, 2009 compared to $68 million for the year ended December 31, 2008. Average CBM lifting costs per unit were $0.57 per thousand cubic feet in 2009 compared to $0.89 per thousand cubic feet in 2008. The decrease in average lifting costs was due to reduced severances taxes primarily due to the reduction in average sales prices in the year ended December 31, 2009. The severance tax decrease also includes an expense reduction attributable to a revised estimate of a pending litigation settlement. Well service costs have also decreased due to lower contract service rig hours needed as a result of less pump maintenance being required in the year ended December 31, 2009. These decreases in unit costs were offset, in part, by an increase related to idling various drilling rigs throughout the Company. Some of CONSOL Energy’s drilling contracts require minimum payments be made to the contracting party when drilling rigs are not being used. The CONSOL Energy drilling program has slowed down pending a change in the economic environment. These charges resulted in an increase to costs.

CBM gathering costs were $88 million for the year ended December 31, 2009 compared to $84 million for the year ended December 31, 2008. The increase of $4 million was attributable to higher volumes produced during the year ended December 31, 2009 compared to the year ended December 31, 2008, offset, in part, by lower average unit costs. Average gathering and compression unit costs were $1.01 per thousand cubic feet in 2009 compared to $1.11 per thousand cubic feet in 2008. The decrease in average gathering and compression costs was attributable to lower gob collection charges primarily due to the Buchanan longwall being idled throughout a portion of 2009. Compression expenses decreased primarily due to a reduction in the number of compressors utilized in the Southwest Pennsylvania operation production field. Due to the slow-down in the drilling program in Southwest Pennsylvania, rented compressors have been returned to more appropriately design the gathering fields to meet existing needs. These decreases in unit costs were offset by increases in firm transportation costs primarily due to acquiring additional capacity in the Southwest Pennsylvania operation after December 31, 2008. Power and fuel costs also increased 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 Virginia production field in order to flow the increasing gas volumes more efficiently.

General and administrative costs for the CBM gas segment were $62 million for the year ended December 31, 2009 compared to $58 million for the year ended December 31, 2008.

General and administrative expenses increased $4 million in the year-to-year comparison. The increased general and administrative expense is attributable to the reassignment of certain CNX Gas personnel in the fourth quarter of 2008 from operational roles to general and administrative oversight functions. The impact of the increased general and administrative costs was offset, in part, by higher volumes produced in 2009.

Depreciation, depletion and amortization expense was $94 million for the year ended December 31, 2009 compared to $70 million for the year ended December 31, 2008.

Production related depreciation, depletion and amortization related to the CBM segment was $71 million for the year ended December 31, 2009 compared to $51 million for the year ended December 31, 2008. The increase in production related depreciation, depletion and amortization was primarily due to increased volumes produced, combined with an increase in the units of production rates for 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 was $23 million for the year ended December 31, 2009 compared to $19 million for the year ended December 31, 2008. Gathering depreciation, depletion and amortization is recorded using the straight-line method and increased $4 million in 2009 due to assets placed in service after December 31, 2008.

CONVENTIONAL SEGMENT:

The Conventional segment had a loss before income tax of $2 million for the year ended December 31, 2009. The revenues and costs associated with the Conventional gas segment for the year ended December 31, 2008 were insignificant, thus a comparison has not been presented.


	2009			2008		Variance			Percent Change
Produced gas Conventional sales volumes (in billion cubic feet)		1.7			—		1.7			100.0	%
Average Conventional sales price per thousand cubic feet sold	$	4.33		$	—	$	4.33			100.0	%
Average Conventional lifting costs per thousand cubic feet sold	$	2.76		$	—	$	2.76			100.0	%
Average Conventional gathering costs per thousand cubic feet sold	$	0.59		$	—	$	0.59			100.0	%
Average Conventional general & administrative costs per thousand cubic feet sold	$	0.46		$	—	$	0.46			100.0	%
Average Conventional depreciation, depletion and amortization costs per thousand cubic feet sold	$	2.30		$	—	$	2.30			100.0	%

Total Conventional costs per thousand cubic feet sold	$	6.11		$	—	$	6.11			100.0	%

Margin	$	(1.78	)	$	—	$	(1.78	)		100.0	%

MARCELLUS SEGMENT:

The Marcellus segment contributed $4 million to the total company earnings before income tax for the year ended December 31, 2009. The revenues and costs associated with the Marcellus gas segment for the year ended December 31, 2008 were insignificant, thus a comparison has not been presented.


	2009		2008		Variance		Percent Change
Produced gas Marcellus sales volumes (in billion cubic feet)		5.0		—		5.0		100.0	%
Average Marcellus sales price per thousand cubic feet sold	$	4.24	$	—	$	4.24		100.0	%
Average Marcellus lifting costs per thousand cubic feet sold	$	0.12	$	—	$	0.12		100.0	%
Average Marcellus gathering costs per thousand cubic feet sold	$	1.12	$	—	$	1.12		100.0	%
Average Marcellus general & administrative costs per thousand cubic feet sold	$	0.74	$	—	$	0.74		100.0	%
Average Marcellus depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.47	$	—	$	1.47		100.0	%

Total Marcellus costs per thousand cubic feet sold	$	3.45	$	—	$	3.45		100.0	%

Margin	$	0.79	$	—	$	0.79		100.0	%

OTHER GAS SEGMENT:

The Other gas segment includes activity not assigned to the CBM, Conventional or Marcellus gas segments. This segment includes purchased gas activity, gas royalty interest activity, exploration and other costs, other corporate expenses, and miscellaneous operational activity outside of the specific gas segments.

Other gas sales volumes are primarily related to production from the Chattanooga Shale in Tennessee. Revenue from this operation was approximately $4 million in 2009. Total costs related to these other sales were $5 million in 2009. The revenues and costs associated with this production for the year ended December 31, 2008 were insignificant.

Royalty interest gas sales represent the revenues for the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. Royalty interest gas sales were $41 million for the year ended December 31, 2009 compared to $79 million for the year ended December 31, 2008. 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			Percent 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 sold	$	4.17	$	9.32	$	(5.15	)		(55.3	)%

Purchased gas sales volumes represent volumes of gas we sold at market prices that were purchased from third-party producers. Purchased gas sales were $7 million for the year ended December 31, 2009 compared to $9 million for the year ended December 31, 2008. The decrease in sales on a unit basis was primarily due to the decrease in market prices.


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

Other income decreased $8 million due to the 2008 receipt of proceeds from our insurance carrier as final settlement of the insurance claim related to the July 2007 Buchanan mine event which idled the mine. The $8 million represented business interruption coverage.

Royalty interest gas costs represent the expenses related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. Royalty interest gas costs were $32 million for the year ended December 31, 2009 compared to $75 million for the year ended December 31, 2008. 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			Percent Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		9.8		8.5		1.3			15.3	%
Average Cost Per thousand cubic feet sold	$	3.30	$	8.69	$	(5.39	)		(62.0	)%

Purchased gas costs represent volumes of gas purchased from third-party producers, less our gathering and marketing fees, which we then sell at market price. Purchased gas volumes sold also reflect the impact of pipeline imbalances. Purchased gas costs were $6 million for the year ended December 31, 2009 compared to $8 million for the year ended December 31, 2008. The lower average cost per thousand cubic feet is due to overall price decreases and contractual differences among customers in the year-to-year comparison.


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

Exploration and Other Costs increased $13 million due to the following items:


	2009		2008		Variance		Percent Change
Dry hole and lease expiration costs	$	10	$	1	$	9		900.0	%
Land and delay rentals		4		1		3		300.0	%
Exploration		3		2		1		50.0	%

Total Exploration and Other Costs	$	17	$	4	$	13		325.0	%

Dry hole and other costs were incurred related to the determination that certain areas where an exploration well was drilled would not be economical to pursue. The costs for the exploration wells, which were previously capitalized, were expensed. In 2009, other costs include costs which were previously capitalized related to a lease. The lease was surrendered due to the properties being widely scattered and not adjacent to any of our existing operating units. Also, costs related to particular permits where management has determined that no drilling will take place have been expensed.

Exploration expense increased primarily due to additional land rental expenses and higher geological and geophysical charges in the year-to-year comparison.

Other corporate expenses have increased $12 million due to the following items:


	2009		2008		Variance			Percent Change
Short-term incentive compensation	$	16	$	8	$	8			100.0	%
Contract settlement		3		—		3			100.0	%
Stock-based compensation		11		12		(1	)		(8.3	)%
Other		3		1		2			200.0	%

Total Other Corporate Expenses	$	33	$	21	$	12			57.1	%

The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for production, unit cost and safety goals. Approximately $12 million of short-term incentive compensation was allocated from CONSOL Energy. The allocation is attributable to the April 2009 management consolidation which resulted in employees being transferred from CNX Gas to CONSOL Energy. The CONSOL Energy employees provide substantially all of the management and administrative functions of CNX Gas, therefore a representative portion of CONSOL Energy’s short-term incentive compensation is now allocated to CNX Gas. This increase was offset, in part, by lower short-term incentive compensation due to fewer CNX Gas employees, resulting in a decrease of $4 million, excluding the CONSOL Energy allocation.

The year ended December 31, 2009 includes $3 million related to a contract buyout with a driller in order to mitigate idle rig charges in certain areas where drilling is not expected to ramp up in the near term. No such transactions occurred during 2008.

Stock-based compensation expense decreased $1 million in the year-to-year comparison. The improvement was related to the CNX Gas performance share units being converted to CONSOL Energy restricted stock units in 2009. The year ended December 31, 2009 contains $4 million of fair value adjustments associated with the exchange offer to convert CNX Gas performance share units into CONSOL Energy restricted stock units.

Miscellaneous other corporate expenses increased $2 million in the year-to-year comparison primarily due to cease use expenses incurred related to the relocation of CNX Gas’ corporate office and various other transactions that occurred throughout both years, none of which were individually material.

Interest expense remained consistent at $8 million in the year-to-year comparison.

Noncontrolling Interest

OTHER SEGMENT ANALYSIS for the year ended December 31, 2009 compared to the year ended December 31, 2008:


	2009			2008			Variance			Percent Change
Sales-Outside	$	273		$	316		$	(43	)		(13.6	)%
Other Income		29			32			(3	)		(9.4	)%

Total Revenue		302			348			(46	)		(13.2	)%
Cost of Goods Sold and Other Charges		267			296			(29	)		(9.8	)%
Depreciation, Depletion & Amortization		20			20			—			—
Taxes Other Than Income Tax		13			11			2			18.2	%
Interest Expense		24			28			(4	)		(14.3	)%

Total Costs		324			355			(31	)		(8.7	)%

Earnings Before Income Tax		(22	)		(7	)		(15	)		214.3	%
Income Tax		221			240			(19	)		(7.9	)%

Net Loss	$	(243	)	$	(247	)	$	4			(1.6	)%

The Other segment includes activity from sales of industrial supplies, transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment had a loss before income tax of $22 million for the year ended December 31, 2009 compared to a loss before income tax of $7 for the year ended December 31, 2008. The other segment also includes total company income tax expense of $221 million for the year ended December 31, 2009 compared to $240 million for the year ended December 31, 2008.

Industrial supplies:

Total revenue from industrial supplies was $196 million for the year ended December 31, 2009 compared to $197 million for the year ended December 31, 2008. The $1 million decrease in revenues was primarily due to lower sales volumes.

Total costs related to industrial supplies were $190 million for the year ended December 31, 2009 compared to $191 million for the year ended December 31, 2008. The $1 million decrease in costs was primarily due to lower sales volumes.

Transportation operations:

Total revenue related to the transportation operations was $84 million for the year ended December 31, 2009 compared to $133 million for the year ended December 31, 2008. The $49 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-to-year comparison. 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.

Total costs related to the transportation operations were $70 million for the year ended December 31, 2009 compared to $101 million for the year ended December 31, 2008. The decrease of $31 million was related to lower tonnage moved and lower employee counts throughout the year ended December 31, 2009.

Miscellaneous Other:

Other income was $22 million for the year ended December 31, 2009 compared to $18 million for the year ended December 31, 2008. The increase relates to a $6 million deferred gain that was recognized in conjunction with the cease use of the previous headquarters. Interest income increased $3 million due to higher average cash balances available to invest in the year-to-year comparison. These increases were offset, in part, by $5 million of various transactions that occurred throughout both periods, none of which were individually material.

Other corporate costs in the other segment include interest cost and various other miscellaneous corporate charges. Total other costs were $64 million for the year ended December 31, 2009 compared to $63 million in the year ended December 31, 2008. Other corporate costs changed due to the following:

•

Other corporate items increased $13 million primarily due to expenses recognized in conjunction with the 2009 cease use of the previous headquarters.

•

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 to commercialize technology to burn waste coal with near zero emissions to generate power fell through. As a result of 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.

•

Other costs decreased $6 million due to various transactions that occurred throughout both periods, none of which were individually material.

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Income Taxes

The effective income tax rate was 28.1% for the year ended December 31, 2009 compared to 33.1% for the year ended December 31, 2008. The decrease in the effective tax rate was attributable to the relationship between pre-tax earnings and percentage depletion. The proportion of coal pre-tax earnings and gas pre-tax earnings also impact the benefit of percentage depletion on the effective tax rate. See “Note 6—Income Taxes” in the Consolidated Financial Statements Item 8 of this Form 10-K for additional explanation of the effective tax rate change in the period-to-period comparison.


	2009			2008			Variance			Percent Change
Total Company 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	)%

Noncontrolling Interest

Noncontrolling interest represents 16.7% of CNX Gas net income which CONSOL Energy did not own at December 31, 2009.

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. See Note 1—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion. 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.

Business Combinations

At acquisition, CONSOL Energy allocates the cost of a business acquisition to the specific tangible and intangible assets acquired and liabilities assumed based upon their relative fair values. Significant judgments and estimates are often made to determine these allocated values, and may include the use of appraisals, consider market quotes for similar transactions, employ discounted cash flow techniques or consider other information CONSOL Energy believes relevant. The finalization of the purchase price allocation will typically take a number of months to complete, and if final values are materially different from initially recorded amounts, adjustments are recorded. Any excess of the cost of a business acquisition over the fair values of the net assets and liabilities acquired is recorded as goodwill which is not amortized to expense. Recorded goodwill of a reporting unit is required to be tested for impairment on an annual basis, and between annual testing dates if events or circumstances change that would more likely than not reduce the fair value of a reporting unit below its net book value.

Subsequent to the finalization of the purchase price allocation, any adjustments to the recorded values of acquired assets and liabilities would be reflected in consolidated statement of operations. Once final, it is not permitted to revise the allocation of the original purchase price, even if subsequent events or circumstances prove

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the original judgments and estimates to be incorrect. In addition, long-lived assets like property and equipment, amortizable intangibles and goodwill may be deemed to be impaired in the future resulting in the recognition of an impairment loss. The assumptions and judgments made when recording business combinations will have an impact on reported results of operations for many years into the future. Purchase price allocations for all recent acquisitions including the Dominion Acquisition have been finalized.

Other Post Employment Benefits (OPEB)

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 participants. 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 2010 have not differed materially from the prior year. Mortality tables have been updated for salary employees to project future mortality improvements for plan participants and spouses. Mortality tables for hourly workers will continue to use the generational experience mortality table based upon the 1974 United Mine Workers of America trust study. Expected trends in future health care cost assumptions have not changed since the prior year. The initial expected trend in health care costs at this year’s measurement date is 8.47% with an ultimate trend rate of 4.50% reached in 2023. A 1.0% decrease in the health care trend rate would decrease interest and service cost for 2010 by approximately $17.5 million. A 1.0% increase in the health care trend rate would increase the interest and service cost by approximately $20.7 million. The discount rate is determined each year at the measurement date. The discount rate is determined 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, 2010. The appropriate discount rate was then selected from resulting discounted cash flows. For the years ended December 31, 2010 and 2009, the discount rate used to calculate the period end liability and the following year’s expense was 5.33% and 5.87%, respectively. A 0.25% increase in the discount rate would have decreased 2010 net periodic postretirement benefit costs by approximately $4.1 million. A 0.25% decrease in the discount rate would have increased 2010 net periodic postretirement benefit costs by approximately $4.8 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, 2010 the average remaining service period is approximately 12 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

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purposes because the majority of the UMWA population of our plan is retired. At December 31, 2010, 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, 2010 Other Postretirement Benefit liability was 0.20% less than expected based on our trend assumption. 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 recorded 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 OPEB liability at December 31, 2010 reflects an increase of approximately $12.3 million due to the Patient Protection and Affordable care Act (PPACA) reform legislation; in particular, the estimated impact of the potential excise tax beginning in 2018. A corresponding increase in Other Comprehensive Loss was also recognized. The estimated increase in the liability was calculated using the following assumptions: testing pre-Medicare and Medicare covered retirees on a combined basis; assuming individual participates have an average 2010 claim cost and future healthcare trend assumptions equal to those used in the year end valuation; assuming the 2018 tax threshold amount to increase for inflation in later years. These assumptions may change once additional guidance becomes available.

The estimated liability recognized in the December 31, 2010 financial statements was $3.3 billion. This amount includes a liability of $2.8 million related to the past service earned by the employees that were retained in the Dominion Acquisition. For the year ended December 31, 2010, we paid approximately $166.0 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, 2010. CONSOL Energy does not expect to contribute to the other postretirement plan in 2011. 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. At the time, the change did not impact the benefits for employees of CNX Gas. However, during 2010 an amendment was adopted to recognize past service at CNX Gas to current employees of CNX Gas who opted out of the plan for additional company contributions into their defined contribution plan and extend coverage to employees previously not eligible to participate in this 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, 2010, compensation increases are assumed to range from 3% to 6% depending on age and job classification. The discount rate is determined each year at the measurement date. The discount rate is

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determined 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, 2010. The appropriate equivalent discount rate was then selected for the resulting discounted pension cash flows. For the years ended December 31, 2010 and 2009, the discount rate used to calculate the period end liability and the following year’s expense was 5.30% and 5.79%, respectively. A 0.25% increase in the discount rate would have decreased the 2010 net periodic pension cost by $1.6 million. A 0.25% decrease in the discount rate would have increased the 2010 net periodic pension cost by $1.6 million. Deferred gains and losses are primarily due to historical changes in the discount rate and earnings on assets differing from expectations. At December 31, 2010 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, 2010 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, 2010 consisted of 61% equity securities and 39% debt securities.

The estimated liability recognized in the December 31, 2010 financial statements was $163.4 million. For the year ended December 31, 2010, we contributed approximately $72.4 million to defined benefit retirement plans other than multi-employer plans trust and to other pension benefits. Our obligations with respect to these liabilities are partially funded at December 31, 2010. CONSOL Energy intends 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 determined 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, 2010. The appropriate equivalent discount rate was then selected from the resulting discounted workers’ compensation cash flows. For the years ended December 31, 2010 and 2009, the discount rate used to calculate the period end liability and the following year’s expense was 5.13% and 5.55%, respectively. A 0.25% increase in the discount rate would have decreased the 2010 workers compensation expense cost by $0.7 million. A 0.25% decrease in the discount rate would have increased the 2010 workers compensation expense by $0.8 million. Deferred gains and losses are primarily due to historical changes in the discount rates, several years of 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 service of active employees that are eligible to file a future workers’ compensation claim. At December 31, 2010, the average remaining service period is approximately 10 years. The estimated liability recognized in the financial statements at December 31, 2010 was approximately $174.5 million. CONSOL Energy’s policy has been to provide for workers’ compensation benefits from operating cash flow. For the year ended December 31, 2010, 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, 2010.

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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 determined 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, 2010. The appropriate equivalent discount rate was then selected from the resulting discounted coal workers’ pneumoconiosis cash flows. For the years ended December 31, 2010 and 2009, the discount rate used to calculate the period end liability and the following year’s expense was 5.21% and 5.84%, respectively. A 0.25% increase in the discount rate would have decreased 2010 coal workers’ pneumoconiosis expense by $0.6 million. A 0.25% decrease in the discount rate would have increased 2010 coal workers’ pneumoconiosis by $0.6 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 assumptions originally reflected. The estimated liability recognized in the financial statements at December 31, 2010 was $184.5 million. For the year ended December 31, 2010, we paid coal workers’ pneumoconiosis benefits of approximately $11.6 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2010.

The Patient Protection and Affordable Care Act (PPACA) impacts CONSOL Energy pneumoconiosis liabilities in that future claims will qualify for payment at a greater rate than has occurred in the past. All CONSOL Energy historical claim data and data from the Department of Labor database was gathered and analyzed to determine the impact of the PPACA. The analysis resulted in an adjustment to the pre-PPACA assumptions which resulted in a $47.7 million reduction to the liability. The impact of the PPACA, including the changes to the legal criteria used to assess and award claims and changes to the law that grant death benefits, regardless of the cause of death, to surviving dependants of miners who have been receiving pneumoconiosis benefits, resulted in an increase of $45.7 million to the liability. These adjustments were treated as adjustments to the actuarial loss and are included in the December 31, 2010 liabilities.

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 $670.9 million at December 31, 2010. This liability is reviewed annually, or when events and circumstances indicate an adjustment is necessary, 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.

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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, 2010, CONSOL Energy has deferred tax assets in excess of deferred tax liabilities of approximately $659.0 million. The deferred tax assets are evaluated periodically to determine if a valuation allowance is necessary.

Deferred tax valuation allowances increased $1.0 million in the year ended December 31, 2010 due to various transactions that occurred throughout 2010, 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 $39.7 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 2018 to 2029. A valuation allowance of $22.9 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 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 $76.3 million at December 31, 2010.

Stock-Based Compensation

As of December 31, 2010, we have issued four types of share based payment awards: options, restricted stock units, performance stock options 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:

•

stock price on measurement date,

•

exercise price defined in the award,

•

expected dividend yield based on historical trend of dividend payouts,

•

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

•

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, 2010, $36.0 million of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.78 years. See Note 18—“Stock-based Compensation” 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—Commitments and Contingent Liabilities in the Notes to the Audited Consolidated Financial Statements in Item 8 in this Form 10-K for further discussion.

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 or development 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

CONSOL Energy 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. 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 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, CONSOL Energy will discontinue hedge accounting prospectively.

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

•

geological conditions;

•

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

•

the assumed effects of regulations and taxes by governmental agencies;

•

assumptions governing future prices; and

•

future operating costs.

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal and gas attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. 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. On May 7, 2010, CONSOL Energy refinanced and extended the previous $1.0 billion credit facility to $1.5 billion, including borrowings and letters of credit, for a term of four years. CONSOL Energy can request an additional $250 million increase in the aggregate borrowing limit amount. The facility was expanded to meet the asset development needs of the company. The obligations under the credit agreement continue to be 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 due March 2012. 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 2.00 to 1.00 through 2010, and no less than 2.50 to 1.00 thereafter, measured quarterly. The minimum interest coverage ratio covenant is calculated as the ratio of EBITDA to cash interest expense for CONSOL Energy and certain of its subsidiaries. The interest coverage ratio was 4.54 to 1.00 at December 31, 2010. The facility includes a maximum leverage ratio covenant of no more than 4.75 to 1.00 through March 2013, and no more than 4.50 to 1.00 thereafter, measured quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CONSOL Energy and certain of its subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and specific letters of credit, less cash on hand, of CONSOL Energy and certain of its subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 3.48 to 1.00 at December 31, 2010. The facility also includes a senior secured leverage ratio covenant of no more than 2.50 to 1.00 through 2010, and no more than 2.00 to 1.00 thereafter, measured quarterly. The senior secured leverage ratio covenant is calculated as the ratio of secured debt to EBITDA. Secured debt is defined as the outstanding borrowings and letters of credit on the revolving credit facility plus the CONSOL Energy Inc. 7.875% bonds due in March 2012. The senior secured leverage ratio was 0.72 to 1.00 at

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December 31, 2010. 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 company. At December 31, 2010, the facility had approximately $155 million drawn and $267 million of letters of credit outstanding, leaving $1.1 billion 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 agency statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.

CONSOL Energy completed an equity offering on March 31, 2010 of 44.3 million shares of common stock, which generated net proceeds of approximately $1.83 billion. On April 1, 2010, CONSOL Energy issued $1.5 billion of 8.00% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020. Covenants in the Notes Indenture limit CONSOL Energy’s ability to incur debt, make investments, sell assets, pay dividends and merge with another company. The equity and bond proceeds were used to complete the Dominion Acquisition for total consideration of approximately $3.47 billion. The acquisition closed on April 30, 2010.

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 obtained surety bonds to satisfy the initial obligation related to the Agreement.

On April 23, 2010, CONSOL Energy amended the accounts receivable securitization facility to allow the Company to receive, on a revolving basis, up to $200 million of short-term funding and letters of credit. Previously, the facility provided up to $165 million. The accounts receivable facility supports sales, on a continuous basis to financial institutions, of eligible trade accounts receivables. The facility was expanded to meet the future cash needs of the Company. 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 based on commercial paper rates plus a charge for administrative services paid to the financial institutions. At December 31, 2010, eligible accounts receivable totaled approximately $200 million. There was no subordinated retained interest at December 31, 2010. Accounts receivable totaling $200 million were reflected as Accounts Receivable—Securitized in Current Assets and Borrowings Under Securitization Facility in Current Liabilities on the Consolidated Balance Sheets at December 31, 2010. There were no letters of credit outstanding against the facility at December 31, 2010.

On May 7, 2010, CNX Gas, a fully consolidated subsidiary of CONSOL Energy, refinanced and extended the existing $200 million credit facility to $700 million, including borrowings and letters of credit, for a term of four years. The facility was expanded to meet the asset development needs of the company. The obligations under the credit agreement are secured by substantially all of the assets of CNX Gas and its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds due March 2012. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. The minimum interest coverage ratio covenant is calculated as the ratio of EBITDA to cash interest expense for CNX Gas Corporation and certain of its subsidiaries. The interest coverage ratio was 69.60 to 1.00 at December 31, 2010. The facility also includes a maximum leverage ratio covenant of no more than 3.50 to 1.00, measured quarterly. The maximum leverage ratio covenant is calculated as the ratio of financial covenant debt to twelve-month trailing EBITDA for CNX Gas Corporation and certain of its subsidiaries. Financial covenant debt is comprised of the outstanding indebtedness and letters of credit, less cash on hand, of CNX Gas Corporation and certain of its subsidiaries. EBITDA, as used in the covenant calculation, excludes non-cash compensation expenses, non-recurring transaction expenses, gains and losses on the sale of assets, uncommon gains and losses, gains and losses on discontinued operations and includes cash distributions received from affiliates plus pro-rata earnings from material acquisitions. The leverage ratio was 0.52 to 1.00 at December 31, 2010. Covenants in the

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facility limit our ability to dispose of assets, make investments, pay dividends and merge with another company. At December 31, 2010, the facility had approximately $129 million drawn and $70 million of letters of credit outstanding, leaving $501 million of unused capacity.

On June 1, 2010, CONSOL Energy completed a tender offer to acquire the 25.3 million shares of CNX Gas common stock and vested stock options that it did not previously own for $38.25 per share. The aggregate purchase price was $991 million. CNX Gas is now a wholly-owned subsidiary of CONSOL Energy. CNX Gas was designated a subsidiary guarantor under the 2017 and 2020 CONSOL Energy Notes Indenture. CNX Gas has to comply with the covenants in the Notes Indenture, which limit the company’s ability to incur debt, make investments, sell assets, pay dividends and merge with another company.

In September 2010, CONSOL Energy refinanced approximately $103 million of industrial development bonds associated with its wholly-owned CNX Marine Terminal in the Port of Baltimore, Maryland. The municipal bonds issued by the Maryland Economic Development Corporation mature on September 1, 2025 and carry an interest rate of 5.75%. The previous bonds carried an interest rate of 6.50% and were due to mature in December 2010 and October 2011.

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, potential counterparty defaults, and further commercial bank failures. 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 hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $76 million at December 31, 2010. The ineffective portion of these contracts was insignificant to earnings in the year ended December 31, 2010. Hedge counterparties consist of commercial banks that participate or have been past participants 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)


	For the Years Ended December 31,
	2010			2009			Change
Cash flows provided by operating activities	$	1,131		$	1,060		$	71
Cash used in investing activities	$	(5,544	)	$	(845	)	$	(4,699	)
Cash provided by (used in) financing activities	$	4,380		$	(288	)	$	4,668

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

•

Operating cash flows increased $129 million due to coal inventories. Coal inventories decreased 1.2 million tons in the year ended December 31, 2010 compared to increasing 1.5 million tons in the year ended December 31, 2009.

•

Operating cash flow increased due to various changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years.

•

Operating cash flow decreased in 2010 due to lower net income attributable to CONSOL Energy shareholders in the period-to-period comparison.

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

•

On April 30, 2010, CONSOL Energy paid $3.47 billion to acquire the Dominion Appalachian E&P business. See Note 2—Acquisitions and Dispositions in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10K for additional details.

•

On May 28, 2010, CONSOL Energy paid $991 million to acquire the shares and vested stock options of CNX Gas common stock which it did not previously own.

•

Total capital expenditures increased $234 million to $1.15 billion in 2010 compared to $920 million in 2009. Capital expenditures for coal and other activities increased $134 million due to various projects including the purchase of various coal lands, additional equipment at various mining locations, continued work on longwall face extensions at various locations, and the Buchanan water handling system. Capital expenditures for the gas segment increased $100 million due to the additional drilling in the period-to-period comparison.

•

Proceeds from the sale of assets were $60 million in the year ended December 31, 2010 compared to $70 million in the year ended December 31, 2009. Proceeds in both periods were primarily related to the sale leaseback of various mining equipment.

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

•

Proceeds of $2.75 billion were received on April 1, 2010 in connection with the issuance of $1.5 billion of 8.00% senior unsecured notes due in 2017 and $1.25 billion of 8.25% senior unsecured notes due in 2020.

•

Proceeds of $1.83 billion were received in connection with the issuance of 44.3 million shares of common stock which was completed on March 31, 2010.

•

In 2010, CONSOL Energy received $150 million of proceeds from the accounts receivable securitization facility. This facility, which has been increased to $200 million, was fully drawn at December 31, 2010. There was $115 million paid under this facility in the year ended December 31, 2009.

•

In 2010, CONSOL Energy paid outstanding borrowings of $260 million under the revolving credit facility. In the year ended December 31, 2009, CONSOL Energy paid outstanding borrowings of $70 million under the revolving credit facility.

•

In 2010, CNX Gas, a 100% owned subsidiary, received $71 million of proceeds from its revolving credit facility. In the year ended December 31, 2009, CNX Gas paid outstanding borrowings of $15 million under its revolving credit facility.

•

In 2010, approximately $84 million was paid for various acquisition and financing fees related to the Dominion Acquisition, the buy-back of the shares and vested stock options of CNX Gas that CONSOL Energy did not previously own, and the various financing activities related to these transactions.

•

Dividends of $86 million were paid in 2010 compared to $72 million in 2009. The increase was due to the 44.3 million additional shares issued on March 31, 2010.

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The following is a summary of our significant contractual obligations at December 31, 2010 (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	$	284,000	$	—	$	—	$	—	$	284,000
Borrowings Under Securitization Facility		200,000		—		—		—		200,000
Purchase Order Firm Commitments		127,624		197,981		25,695		—		351,300
Gas Firm Transportation		41,289		68,215		62,454		312,085		484,043
Long-term Debt		16,579		262,110		5,173		2,861,745		3,145,607
Interest on Long-term Debt		249,311		469,534		459,856		824,648		2,003,349
Capital (Finance) Lease Obligations		8,154		12,699		9,819		34,884		65,556
Interest on Capital (Finance) Lease Obligations		4,478		7,400		5,919		8,113		25,910
Operating Lease Obligations		77,414		120,018		83,217		125,829		406,478
Other Long-term Liabilities(a)		537,797		588,023		582,853		2,886,292		4,594,965

Total Contractual Obligations(b)	$	1,546,646	$	1,725,980	$	1,234,986	$	7,053,596	$	11,561,208

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 2011 contributions are expected to be approximately $63.6 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, 2010, CONSOL Energy had total long-term debt of $3.211 billion outstanding, including the current portion of long-term debt of $25 million. This long-term debt consisted of:

•

An aggregate principal amount of $1.5 billion of 8.00% senior unsecured notes due in April 2017. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CONSOL Energy’s subsidiaries.

•

An aggregate principal amount of $1.25 billion of 8.25% senior unsecured notes due in April 2020. Interest on the notes is payable April 1 and October 1 of each year. Payment of the principal and interest on the notes is guaranteed by most of CONSOL Energy’s subsidiaries.

•

An aggregate principal amount of $250 million of 7.875% notes due in March 2012. 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 is 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 $103 million of industrial revenue bonds which were issued to finance the Baltimore port facility and bear interest at 5.75% per annum and mature in September 2025.

•

$32 million in advance royalty commitments with an average interest rate of 7.56% per annum.

•

An aggregate principal amount of $10 million on a variable rate note due in December 2012 that bears interest at 6.10% at December 31, 2010. 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 $66 million of capital leases with a weighted average interest rate of 7.36% per annum.

At December 31, 2010, CONSOL Energy also had $155 million of aggregate principal amounts of outstanding borrowings and approximately $267 million of letters of credit outstanding under the $1.5 billion senior secured revolving credit facility.

At December 31, 2010, CONSOL Energy had $200 million of borrowings under the securitization facility.

At December 31, 2010, CNX Gas, a wholly owned subsidiary, had $129 million of aggregate principal amounts of outstanding borrowings and approximately $70 million of letters of credit outstanding under its $700 million secured revolving credit facility.

Total Equity and Dividends

CONSOL Energy had total equity of $2.9 billion at December 31, 2010 and $2.0 billion at December 31, 2009. Total equity increased primarily due to the sale of approximately 44.3 million shares of common stock which resulted in net proceeds of approximately $1.83 billion. Total equity also increased due to net income attributable to CONSOL Energy shareholders for the year ended December 31, 2010 and amortization of stock-based compensation awards. These increases were offset, in part, by the acquisition of the noncontrolling interest in CNX Gas, changes in the actuarial long-term liabilities, changes in cash flow hedging and the declaration of dividends. See the Consolidated Statements of Stockholders’ Equity in Item 8 of this Form 10K for additional details.

Dividend information for the current year to date is as follows:


Declaration Date	Amount Per Share	Record Date	Payment Date
January 28, 2011	$0.10	February 8, 2011	February 18, 2011
November 1, 2010	$0.10	November 12, 2010	November 26, 2010
July 30, 2010	$0.10	August 13, 2010	August 23, 2010
April 30, 2010	$0.10	May 10, 2010	May 20, 2010
January 29, 2010	$0.10	February 9, 2010	February 19, 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 in excess of an annual rate of $0.40 per share when our leverage ratio exceeds 4.50 to 1.00 or our availability is less than or equal to $100 million. The leverage ratio was 3.48 to 1.00 and our availability was approximately $1.1 billion at December 31, 2010. The credit facility does not permit dividend payments in the event of default. The indenture to the 2017 and 2020 notes limits dividends to $0.40 per share annually unless several conditions are met. Conditions include no defaults, ability to incur additional debt and other payment limitations under the indentures. There were no defaults under the credit facility or the indentures in the year ended December 31, 2010.

Off-Balance Sheet Transactions

CONSOL Energy does not maintain 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 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

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Audited Consolidated Financial Statements in Item 8 of this Form 10-K. 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, 2010. See Note 17—Other Employee Benefit Plans in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K for further discussion. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters of credit to secure our financial obligations for employee-related, environmental, performance and various other items which are not reflected on the balance sheet at December 31, 2010. Management believes these items will expire without being funded. See Note 24—Commitments and Contingent Liabilities of this Form 10-K for additional details of the various financial guarantees that have been issued by CONSOL Energy.

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 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—Significant Accounting Policies in the Notes to the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.

A sensitivity analysis has been performed to determine the incremental effect on future earnings, related to open derivative at December 31, 2010. A hypothetical 10 percent decrease in future natural gas prices would increase future earnings related to derivatives by $36.8 million. Similarly, a hypothetical increase in future natural gas prices would decrease future earnings related to derivatives by $36.8 million.

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Hedging Volumes

Our hedged volumes as of January 24, 2011 are as follows:


	For the Three Months Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2011 Fixed Price Volumes
Hedged Mcf		13,107,483		18,539,961		18,743,698		18,793,509		69,184,651
Weighted Average Hedge Price/Mcf	$	5.53	$	5.21	$	5.21	$	5.27	$	5.29

2012 Fixed Price Volumes
Hedged Mcf		6,567,010		6,567,010		6,639,175		6,639,175		26,412,370
Weighted Average Hedge Price/Mcf	$	6.02	$	6.02	$	6.02	$	6.02	$	6.02

2013 Fixed Price Volumes
Hedged Mcf		1,855,670		1,876,289		1,896,907		1,896,907		7,525,773
Weighted Average Hedge Price/Mcf	$	5.08	$	5.08	$	5.08	$	5.08	$	5.08

2014 Fixed Price Volumes
Hedged Mcf		1,855,670		1,876,289		1,896,907		1,896,907		7,525,773
Weighted Average Hedge Price/Mcf	$	5.30	$	5.30	$	5.30	$	5.30	$	5.30

CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties.

CONSOL Energy’s interest expense is sensitive to changes in the general level of interest rates in the United States. At December 31, 2010, CONSOL Energy had $3,211 million aggregate principal amount of debt outstanding under fixed-rate instruments and $484 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 $155 million of borrowings outstanding at December 31, 2010. CONSOL Energy’s revolving credit facility bore interest at a weighted average rate of 3.94% per annum during the year ended December 31, 2010. 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 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 $129 million at December 31, 2010 and bore interest at a weighted average rate of 2.18% per annum during the year ended December 31, 2010. 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.

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Item 8.

Financial Statements and Supplementary Data.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Report of Independent Registered Public Accounting Firm		117
Consolidated Statements of Income for the Years Ended December 31, 2010, 2009 and 2008		118
Consolidated Balance Sheets at December 31, 2010 and 2009		119
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008		120
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		121
Notes to the Audited Consolidated Financial Statements		122

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of CONSOL Energy Inc. and Subsidiaries

We have audited the accompanying consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. 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 based on our audits.

We conducted our audits 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 audits provide 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, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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—Significant Accounting Policies in the Notes to the Consolidated Financial Statements, effective December 31, 2009, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserves estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), CONSOL Energy, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2010, 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 10, 2011 expressed an unqualified opinion.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 10, 2011

117

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)


	For the Years Ended December 31,
	2010			2009			2008
Sales—Outside	$	4,938,703		$	4,311,791		$	4,181,569
Sales—Purchased Gas		11,227			7,040			8,464
Sales—Gas Royalty Interest		62,869			40,951			79,302
Freight—Outside		125,715			148,907			216,968
Other Income (Note 3)		97,507			113,186			166,142

Total Revenue and Other Income		5,236,021			4,621,875			4,652,445
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)		3,262,327			2,757,052			2,843,203
Acquisition and Financing Fees		65,363			—			—
Purchased Gas Costs		9,736			6,442			8,175
Gas Royalty Interests Costs		53,775			32,376			73,962
Freight Expense		125,544			148,907			216,968
Selling, General and Administrative Expenses		150,210			130,704			124,543
Depreciation, Depletion and Amortization		567,663			437,417			389,621
Interest Expense (Note 4)		205,032			31,419			36,183
Taxes Other Than Income (Note 5)		328,458			289,941			289,990
Black Lung Excise Tax Refund		—			(728	)		(55,795	)

Total Costs		4,768,108			3,833,530			3,926,850

Earnings Before Income Taxes		467,913			788,345			725,595
Income Taxes (Note 6)		109,287			221,203			239,934

Net Income		358,626			567,142			485,661
Less: Net Income Attributable to Noncontrolling Interest		(11,845	)		(27,425	)		(43,191	)

Net Income Attributable to CONSOL Energy Inc. Shareholders	$	346,781		$	539,717		$	442,470

Earnings Per Share (Note 1):
Basic	$	1.61		$	2.99		$	2.43

Dilutive	$	1.60		$	2.95		$	2.40

Weighted Average Number of Common Shares Outstanding (Note 1):
Basic		214,920,561			180,693,243			182,386,011

Dilutive		217,037,804			182,821,136			184,679,592

Dividends Paid Per Share	$	0.40		$	0.40		$	0.40

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

118

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)


	December 31,
	2010			2009
ASSETS
Current Assets:
Cash and Cash Equivalents	$	32,794		$	65,607
Accounts and Notes Receivable:
Trade		252,530			317,460
Other Receivables		21,589			15,983
Accounts Receivable—Securitized (Note 9)		200,000			50,000
Inventories (Note 8)		258,538			307,597
Recoverable Income Taxes		32,528			—
Deferred Income Taxes (Note 6)		174,171			73,383
Prepaid Expenses		142,856			161,006

Total Current Assets		1,115,006			991,036
Property, Plant and Equipment (Note 10):
Property, Plant and Equipment		14,951,358			10,681,955
Less—Accumulated Depreciation, Depletion and Amortization		4,822,107			4,557,665

Total Property, Plant and Equipment—Net		10,129,251			6,124,290
Other Assets:
Deferred Income Taxes (Note 6)		484,846			425,297
Restricted Cash		20,291			—
Investment in Affiliates		93,509			83,533
Other		227,707			151,245

Total Other Assets		826,353			660,075

TOTAL ASSETS	$	12,070,610		$	7,775,401

LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	354,011		$	269,560
Short-Term Notes Payable (Note 11)		284,000			472,850
Current Portion of Long-Term Debt (Note 13 and Note 14)		24,783			45,394
Accrued Income Taxes		—			27,944
Borrowings Under Securitization Facility (Note 9)		200,000			50,000
Other Accrued Liabilities (Note 12)		801,991			612,838

Total Current Liabilities		1,664,785			1,478,586
Long-Term Debt:
Long-Term Debt (Note 13)		3,128,736			363,729
Capital Lease Obligations (Note 14)		57,402			59,179

Total Long-Term Debt		3,186,138			422,908
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions (Note 15)		3,077,390			2,679,346
Pneumoconiosis Benefits (Note 16)		173,616			184,965
Mine Closing (Note 7)		393,754			397,320
Gas Well Closing (Note 7)		130,978			85,992
Workers’ Compensation (Note 16)		148,314			152,486
Salary Retirement (Note 15)		161,173			189,697
Reclamation (Note 7)		53,839			27,105
Other		144,610			132,517

Total Deferred Credits and Other Liabilities		4,283,674			3,849,428

TOTAL LIABILITIES		9,134,597			5,750,922
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 227,289,426 Issued and 226,162,133 outstanding at December 31, 2010; 183,014,426 Issued and 181,086,267 Outstanding at December 31, 2009		2,273			1,830
Capital in Excess of Par Value		2,178,604			1,033,616
Preferred Stock, 15,000,000 authorized; None issued and outstanding		—			—
Retained Earnings		1,680,597			1,456,898
Accumulated Other Comprehensive Loss (Note 19)		(874,338	)		(640,504	)
Common Stock in Treasury, at Cost—1,127,293 Shares at December 31, 2010 and
1,928,159 Shares at December 31, 2009		(42,659	)		(66,292	)

Total CONSOL Energy Inc. Stockholders’ Equity		2,944,477			1,785,548
Noncontrolling Interest		(8,464	)		238,931

TOTAL EQUITY		2,936,013			2,024,479

TOTAL LIABILITIES AND EQUITY	$	12,070,610		$	7,775,401

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

119

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, 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 (2,112,100 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
Net Income		—			—			346,781			—			—			346,781			11,845			358,626
Treasury Rate Lock (Net of $49 Tax)		—			—			—			(84	)		—			(84	)		—			(84	)
Gas Cash Flow Hedge (Net of $15,983 Tax)		—			—			—			(30,543	)		—			(30,543	)		5,252			(25,291	)
Actuarially Determined Long-Term Liability Adjustments (Net of $154,773 Tax)		—			—			—			(221,233	)		—			(221,233	)		5			(221,228	)
Purchase of CNX Gas Noncontrolling Interest		—			—			—			18,026			—			18,026			—			18,026

Comprehensive Income (Loss)		—			—			346,781			(233,834	)		—			112,947			17,102			130,049
Issuance of Treasury Stock		—			—			(37,221	)		—			23,633			(13,588	)		—			(13,588	)
Issuance of Common Stock		443			1,828,419			—			—			—			1,828,862			—			1,828,862
Issuance of CNX Gas Stock		—			—			—			—			—			—			2,178			2,178
Purchase of CNX Gas Noncontrolling Interest		—			(746,052	)		—			—			—			(746,052	)		(263,008	)		(1,009,060	)
Tax Benefit from Stock-Based Compensation		—			15,100			—			—			—			15,100			—			15,100
Stock-Based Compensation Awards to CNX Gas Employees		—			2,126			—			—			—			2,126			(1,771	)		355
Amortization of Stock-Based Compensation Awards		—			45,395			—			—			—			45,395			2,198			47,593
Net Change in Crown Drilling Noncontrolling Interest		—			—			—			—			—			—			(4,094	)		(4,094	)
Dividends ($0.40 per share)		—			—			(85,861	)		—			—			(85,861	)		—			(85,861	)

Balance at December 31, 2010	$	2,273		$	2,178,604		$	1,680,597		$	(874,338	)	$	(42,659	)	$	2,944,477		$	(8,464	)	$	2,936,013

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

120

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

(Dollars in thousands, except per share data)


	For the Years Ended December 31,
	2010			2009			2008
Cash Flows from Operating Activities:
Net Income	$	358,626		$	567,142		$	485,661
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization		567,663			437,417			389,621
Stock-based Compensation		47,593			39,032			25,186
Gain on Sale of Assets		(9,908	)		(15,121	)		(23,368	)
Amortization of Mineral Leases		4,160			3,970			4,871
Deferred Income Taxes		17,029			47,430			135,594
Equity in Earnings of Affiliates		(21,428	)		(15,707	)		(11,140	)
Changes in Operating Assets:
Accounts and Notes Receivable		(96,245	)		84,597			(79,747	)
Inventories		48,919			(79,787	)		(53,994	)
Prepaid Expenses		(20,974	)		10,730			(5,032	)
Changes in Other Assets		7,237			(724	)		17,081
Changes in Operating Liabilities:
Accounts Payable		78,839			(70,458	)		64,851
Other Operating Liabilities		129,230			80,527			(14,020	)
Changes in Other Liabilities		(15,443	)		(45,883	)		51,546
Other		36,014			17,286			2,754

Net Cash Provided by Operating Activities		1,131,312			1,060,451			989,864

Cash Flows from Investing Activities:
Capital Expenditures		(1,154,024	)		(920,080	)		(1,061,669	)
Acquisition of Dominion Exploration and Production Business		(3,470,212	)		—			—
Purchase of CNX Gas Noncontrolling Interest		(991,034	)		—			—
Proceeds from Sale of Assets		59,844			69,884			28,193
Purchase of Stock in Subsidiary		—			—			(67,259	)
Net Investment in Equity Affiliates		11,452			4,855			1,879

Net Cash Used in Investing Activities		(5,543,974	)		(845,341	)		(1,098,856	)

Cash Flows from Financing Activities:
(Payments on) Proceeds from Short-Term Debt		(188,850	)		(84,850	)		310,200
Payments on Miscellaneous Borrowings		(11,412	)		(19,190	)		(10,414	)
Proceeds from (Payments on) Securitization Facility		150,000			(115,000	)		39,600
Proceeds from Issuance of Long-Term Notes		2,750,000			—			—
Tax Benefit from Stock-Based Compensation		15,365			3,270			22,003
Dividends Paid		(85,861	)		(72,292	)		(72,957	)
Proceeds from Issuance of Common Stock		1,828,862			—			—
Issuance of Treasury Stock		5,993			2,547			15,215
Debt Issuance and Financing Fees		(84,248	)		—			—
Purchases of Treasury Stock		—			—			(97,794	)
Noncontrolling Interest Member Distribution		—			(2,500	)		—

Net Cash Provided By (Used In) Financing Activities		4,379,849			(288,015	)		205,853

Net (Decrease) Increase in Cash and Cash Equivalents		(32,813	)		(72,905	)		96,861
Cash and Cash Equivalents at Beginning of Period		65,607			138,512			41,651

Cash and Cash Equivalents at End of Period	$	32,794		$	65,607		$	138,512

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

See Note 20—Supplemental Cash Flow

121

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO THE 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. 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. The accounts of variable interest entities, where CONSOL Energy is the primary beneficiary, are included in the Consolidated Financial Statements. 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 business combinations, other postretirement benefits, coal workers’ pneumoconiosis, workers’ compensation, salary retirement benefits, stock-based compensation, reclamation, asset retirement obligations, 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. There were no material financing receivables with a contractual maturity greater than one year.

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 coal and gas operations.

122

Property, Plant and Equipment:

Property, plant and equipment is recorded at fair value upon acquisition. 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.

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 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.

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, or at a minimum once a year, 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 well activity is accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory or development wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory or development 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, or at a minimum once a year; those revisions are accounted for prospectively as changes in accounting estimates.

123

Depreciation of 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
Machinery and equipment		3 to 25
Leasehold improvements		Life of Lease

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 effect from changes in estimates is disclosed in the period the change occurs.

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 seven 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 $1,813 and $4,211 was recognized in Cost of Goods Sold and Other Operating Charges for the year ended December 31, 2010 and 2009, respectively, for the impairment of sales contract assets previously acquired. 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.

Gas Reserve Estimates

In December 2009, CONSOL adopted authoritative guidance issued by the FASB on extractive activities for oil and gas reserve estimation and disclosures. 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 years ended December 31, 2010 and 2009.

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

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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.

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.

Restricted Cash:

Restricted cash includes a deposit into escrow as security to perfect CONSOL Energy’s appeal to the Pennsylvania Environmental Hearing Board under the applicable statute related to the Ryerson dam litigation. For additional details see Note 24—Commitments and Contingent Liabilities.

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.

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 Costs:

CONSOL Energy accrues for mine closing costs, reclamation 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

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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, which includes treatment of water and the reclamation of land upon exhaustion of coal and gas reserves.

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. The cost of these retiree benefits are recognized over the employees’ service period. CONSOL Energy uses actuarial methods and assumptions in the valuation of defined benefit obligations and the determination of expense. Differences between actual and expected results or changes in the value of obligations and plan assets are recognized through Other Comprehensive Income. Provisions are determined on an actuarial basis.

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.

CONSOL Energy 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.

CONSOL Energy 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.

CONSOL Energy purchases gas produced by third parties at market prices less a fee. The gas purchased from third party producers is then resold 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 CONSOL Energy from the third party producer.

Royalty Interest Gas Sales represent the revenues related to the portion of production belonging to royalty interest owners sold by CONSOL Energy.

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.

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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 presented 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.

Issuance of Common Stock:

On March 31, 2010, CONSOL Energy issued 44,275,000 shares of common stock, which generated net proceeds of $1,828,862 to fund, in part, the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion Acquisition). The acquisition transaction closed on April 30, 2010. See Note 2—Acquisitions and Dispositions for further discussion of the Dominion Acquisition.

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.

There were no cash expenditures under our repurchase program for the years ended December 31, 2010 and 2009. For the year ended December 31, 2008, we had cash expenditures under our repurchase program of $97,794 funded primarily by cash generated from operations. The total common shares repurchased for the year ended December 31, 2008 was 2,741,300 at an average cost of $35.59 per share.

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—Stock Based Compensation for further discussion.

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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 share 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 share 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,
	2010		2009		2008
Anti-Dilutive Options		813,833		695,743		370,987
Anti-Dilutive Restricted Stock Units		1,960		5,274		—
Anti-Dilutive Performance Share Units		—		41,581		18,176

		815,793		742,598		389,163


	For the Years Ended December 31,
	2010		2009		2008
Net income attributable to CONSOL Energy Inc. shareholders	$	346,781	$	539,717	$	442,470

Average shares of common stock outstanding:
Basic		214,920,561		180,693,243		182,386,011
Effect of stock-based compensation awards		2,117,243		2,127,893		2,293,581

Dilutive		217,037,804		182,821,136		184,679,592

Earnings per share:
Basic	$	1.61	$	2.99	$	2.43

Dilutive	$	1.60	$	2.95	$	2.40

Shares of common stock outstanding were as follows:


	2010		2009		2008
Balance, beginning of year		181,086,267		180,549,851		182,291,623
Issuance related to Stock-Based Compensation(1)		800,866		536,416		1,027,250
Issuance of Common Stock(2)		44,275,000		—		—
Repurchased-Treasury Stock Shares		—		—		(656,922	)
Repurchased-Retired Shares		—		—		(2,112,100	)

Balance, end of year		226,162,133		181,086,267		180,549,851

(1)	See Note 18—Stock-Based Compensation for additional information.

(2)	See Issuance of Common Stock in Note 1 for additional information.

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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 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:

CONSOL Energy accounts for its business acquisitions under the acquisition 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.

Reclassifications:

Certain reclassifications of prior period data have been made to conform to the year ended December 31, 2010 as required by the Transfers and Servicing Topic of the FASB Accounting Standards Codification. See Note 9—Accounts Receivable Securitization for further discussion of the reclassifications of prior period data related to the Accounts Receivable Securitization Facility.

Subsequent Events:

We have evaluated all subsequent events through the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.

Note 2—Acquisitions and Dispositions:

In December 2010, CONSOL Energy completed a sale-leaseback of longwall shields for McElroy Mine. Cash proceeds from the sale were $33,383, 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 September 2010, CONSOL Energy completed a sale-leaseback of longwall shields for Enlow Fork. Cash proceeds from the sale were $14,551, 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 June 2010, CONSOL Energy paid Yukon Pocahontas Coal Company $30,000 cash to acquire certain coal reserves and $20,000 cash in advanced royalty payments in accordance with the settlement referenced in Note 24—Commitments and Contingent Liabilities.

On June 1, 2010, CONSOL Energy completed the acquisition of CNX Gas Corporation (CNX Gas) outstanding common stock for a cash payment of $966,811 pursuant to a tender offer followed by a short-form merger in which CNX Gas became a wholly owned subsidiary. All of the shares of CNX Gas that were not

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already owned by CONSOL Energy were acquired at a price of $38.25. CONSOL Energy previously owned approximately 83.3% of the approximately 151 million shares of CNX Gas common stock outstanding. An additional $24,223 cash payment was made to cancel previously vested CNX Gas stock options. CONSOL Energy financed the acquisition of CNX Gas shares by means of internally generated funds, borrowings under its credit facilities and proceeds from its offering of common stock.

On April 30, 2010, CONSOL Energy completed the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. (Dominion Acquisition) for a cash payment of $3,470,212, which was principally allocated to oil and gas properties, wells and well related equipment. The acquisition, which was accounted for under the acquisition method of accounting, includes approximately 1 trillion cubic feet equivalents (Tcfe) of net proved reserves and 1.46 million net acres of oil and gas rights within the Appalachian Basin. Included in the acreage holdings are approximately 500 thousand prospective net Marcellus Shale acres located predominantly in southwestern Pennsylvania and northern West Virginia. Dominion is a producer and transporter of natural gas as well as a provider of electricity and related services. The acquisition is expected to enhance CONSOL Energy’s position in the strategic Marcellus Shale fairway by increasing its development assets.

The following table summarizes the final estimates of the fair value of identifiable assets acquired and liabilities assumed as of the date of the acquisition.


	Acquisition Date Fair Value
Assets
Current Assets:
Inventory	$	301
Prepaid Expenses		2,498

Total Current Assets		2,799
Property, plant and equipment		3,525,444
Deferred Tax Asset		14,741
Total Assets	$	3,542,984

Liabilities
Current Liabilities:
Other Accrued Liabilities	$	19,725
Deferred Credits and Other Liabilities:
Gas Well Closing		47,409
Postretirement Benefits Other Than Pension		2,800
Salary Retirement		900
Other		1,938

Total Deferred Credits and Other Liabilities		53,047
Total Liabilities	$	72,772

Net Assets Acquired	$	3,470,212

The results of operations of the acquired entities are included in CONSOL Energy’s Consolidated Statements of Income as of May 1, 2010. Net revenues and net income (loss) resulting from the Dominion Acquisition that were included in CONSOL Energy’s operating results were $133,850 and $(5,364), respectively, for the year ended December 31, 2010.

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The unaudited pro forma results for the periods presented below are prepared as if the transaction occurred as of the beginning of the prior year. Pro forma adjustments include estimated operating results, acquisition and financing fees incurred, additional interest related to the $2,750,000 of senior unsecured notes and 44,275,000 shares of common stock issued in connection with the transaction.


	For the Year Ended December 31,
	2010		2009
Total Revenue and Other Income	$	5,303,008	$	4,790,048
Earnings Before Income Taxes	$	474,698	$	497,331
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	350,839	$	366,156
Basic Earnings Per Share	$	1.35	$	1.63
Dilutive Earnings Per Share	$	1.34	$	1.61

The pro forma results are not necessarily indicative of what actually would have occurred if the Dominion E&P Acquisition had been completed as of January 1, 2009, nor are they necessarily indicative of future consolidated results.

In the year ended December 31, 2010, CONSOL Energy incurred $65,363 of acquisition-related costs as a direct result of the Dominion Acquisition and purchase of CNX Gas Noncontrolling Interest. These expenses have been included within Acquisition and Financing Fees on the Consolidated Statements of Income for the year ended December 31, 2010.

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 FASB Accounting Standards Codification related to the Company’s previous headquarters. This liability was recorded in Other Liabilities on the Consolidated Balance Sheets at December 31, 2009. Total expense related to this transaction was $12,500 which was recognized in Cost of Goods Sold and Other Operating Charges. This amount included the fair value of the remaining lease payments of $10,974 as well as the removal of a related asset of $1,526. Additionally, $5,832 was recognized in Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the premises that occurred in 2005. In the year ended December 31, 2010, the cease use expense was reduced by $2,999 as a result of a change in estimated cash flows.

In March 2010, CONSOL Energy completed the sale of Jones Fork Mining Complex as part of a litigation settlement with Kentucky Fuel Corporation. No cash proceeds were received and $10,482 of litigation settlement expense was recorded in Cost of Goods Sold and Other Operating Charges. The loss recorded was net of $8,700 related to the fair value of estimated amounts to be collected related to an override royalty on future mineable and merchantable coal extracted and sold from the property.

In August 2009, CONSOL Energy completed the lease assignment of CNX Gas’ previous headquarters. Total expense related to this transaction for the year ended December 31, 2010 was $1,500, which was recognized in Cost of Goods Sold and Other Operating Charges.

In August 2009, CONSOL Energy completed a sale-leaseback 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.

In July 2009, CONSOL Energy, through a subsidiary, leased approximately 20,000 acres having Marcellus Shale potential from NiSource Energy Ventures, LLC, a subsidiary of 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.

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In February 2009, CONSOL Energy completed a sale-leaseback 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 pro forma 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 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 was 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.

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. This amount is included in capital expenditures in Cash used in Investing Activities on the Consolidated Statements of Cash Flows. 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 previously 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. This amount is included in capital expenditures in Cash used in Investing Activities on the Consolidated Statements of Cash Flows. Knox Energy, LLC had been proportionately consolidated into CONSOL Energy’s financial statements during 2008. 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.

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Note 3—Other Income:


	For the Years Ended December 31,
	2010		2009		2008
Equity in earnings of affiliates	$	21,428	$	15,707	$	11,140
Royalty income		14,688		17,249		20,673
Gain on disposition of assets		9,908		15,121		23,368
Service income		9,796		11,796		14,298
Interest income		7,642		5,052		2,363
Charter & tramp towing income		4,080		4,838		11,164
Contract settlements		—		12,450		—
Buchanan roof collapse insurance proceeds		—		—		50,000
Other		29,965		30,973		33,136

Total Other Income	$	97,507	$	113,186	$	166,142

Note 4—Interest Expense:


	For the Years Ended December 31,
	2010			2009			2008
Interest on debt	$	213,832		$	39,524		$	45,627
Interest on other payables		4,593			3,766			2,718
Interest capitalized		(13,393	)		(11,871	)		(12,162	)

Total Interest Expense	$	205,032		$	31,419		$	36,183

Note 5—Taxes Other Than Income:


	For the Years Ended December 31,
	2010			2009			2008
Production taxes	$	202,536		$	183,307		$	188,581
Property taxes		57,889			47,934			44,107
Payroll taxes		54,631			48,702			49,829
Capital stock & franchise tax		11,201			8,895			6,568
Virginia employment enhancement tax credit		(4,777	)		(3,715	)		(4,190	)
Other		6,978			4,818			5,095

Total Taxes Other Than Income	$	328,458		$	289,941		$	289,990

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Note 6—Income Taxes:

Income taxes (benefits) provided on earnings consisted of:


	For the Years Ended December 31,
	2010			2009			2008
Current:
U.S. Federal	$	82,031		$	134,231		$	87,658
U.S. State		13,652			41,482			14,549
Non-U.S.		(3,425	)		(1,940	)		2,133

		92,258			173,773			104,340
Deferred:
U.S. Federal		8,463			49,672			101,869
U.S. State		8,566			(2,242	)		33,725

		17,029			47,430			135,594

Total Income Taxes	$	109,287		$	221,203		$	239,934

The components of the net deferred tax assets are as follows:


	December 31,
	2010			2009
Deferred Tax Assets:
Postretirement benefits other than pensions	$	1,251,641		$	1,084,523
Mine closing		144,131			134,362
Alternative minimum tax		141,758			102,029
Pneumoconiosis benefits		71,661			81,724
Workers’ compensation		67,025			69,562
Salary retirement		65,309			68,820
Net operating loss		58,428			53,133
Mine subsidence		34,659			30,162
Reclamation		31,177			11,978
Capital lease		27,918			31,301
Other		129,293			85,220

Total Deferred Tax Assets		2,023,000			1,752,814
Valuation Allowance**		(62,668	)		(61,623	)

Net Deferred Tax Assets		1,960,332			1,691,191
Deferred Tax Liabilities:
Property, plant and equipment		(1,221,362	)		(1,101,133	)
Advance mining royalties		(31,574	)		(25,568	)
Gas hedge		(29,209	)		(46,129	)
Other		(19,170	)		(19,681	)

Total Deferred Tax Liabilities		(1,301,315	)		(1,192,511	)

Net Deferred Tax Assets	$	659,017		$	498,680

**	Valuation allowances of ($778) and ($61,890) have been allocated between current and long-term deferred tax assets respectively for 2010. Valuation allowances of ($3,051) and ($58,572) have been allocated between current and long-term deferred tax assets respectively for 2009.

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, 2010 and 2009, positive evidence considered

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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.

CONSOL Energy continues to report, on an after federal tax adjusted basis, a deferred tax asset related to state operating losses of $58,428 with a related valuation allowance of $39,744 at December 31, 2010. The deferred tax asset related to state operating losses, on an after federal tax adjusted basis, was $53,133 with a related valuation allowance of $37,052 at December 31, 2009. A review of positive and negative evidence regarding these state operating benefits, primarily the history of book and tax losses on a separate company basis, concluded that a valuation allowance for various CONSOL Energy subsidiaries was warranted. The net operating losses expire at various times between 2011 and 2029.

The deferred tax assets attributable to future deductible temporary difference for certain CONSOL Energy subsidiaries with histories of financial and tax losses was also reviewed for positive and negative evidence regarding the realization of the deferred tax assets. A valuation allowance of $22,924 and $24,571 was recognized at December 31, 2010 and 2009, respectively. Included in the valuation allowance against the future deductible temporary differences at December 31, 2010 and 2009, were $9,639 and $7,952 of allowances which were recognized through Other Comprehensive income. These allowances relate to actuarial gains/losses for other postretirement, pension and long-term disability benefits that were recognized through Other Comprehensive Income.

Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data, the feasibility of future tax planning strategies and other relevant information. Adjustments to valuation allowances against deferred tax assets in future periods, as appropriate, could materially impact net income.

We estimate that CONSOL Energy will pay federal alternative minimum tax of $21,607 for the year ended December 31, 2010, thereby creating an additional deferred tax asset associated with the prior years’ minimum tax credits. During 2010, the deferred tax asset associated with the federal alternative minimum tax credits was also increased $18,122 as a result of the 2009 accrual to 2009 return adjustments. These increases resulted in an alternative minimum tax deferred tax asset of $141,758 which is expected to be fully realized.

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,
	2010						2009						2008
	Amount			Percent			Amount			Percent			Amount			Percent
Statutory U.S. federal income tax rate	$	163,770			35.0	%	$	275,921			35.0	%	$	253,958			35.0	%
Excess tax depletion		(70,812	)		(15.1	)		(68,787	)		(8.7	)		(48,859	)		(6.7	)
Effect of domestic production activities		(5,633	)		(1.2	)		(12,707	)		(1.6	)		(7,721	)		(1.1	)
Net effect of state tax		13,468			2.9			25,377			3.2			31,169			4.3
Effect of foreign tax		(3,424	)		(0.7	)		(343	)		—			2,133			0.3
Other		11,918			2.5			1,742			0.2			9,254			1.3

Income Tax Expense/Effective Rate	$	109,287			23.4	%	$	221,203			28.1	%	$	239,934			33.1	%

The 2009 rate reconciliation includes $2,295 of Federal income tax benefit as a result of settling the Internal Revenue Service audit for the tax years 2004 and 2005 in the Other line. Certain adjustments to taxable income for the 2009 period resulted in changes to permanent tax items that decreased income tax expense for the year. Also, the 2009 rate reconciliation includes $3,563 foreign taxes paid in the Other line that the company chose to claim as Foreign Tax Credits against taxable income instead of deducting those taxes to arrive at taxable income.

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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 received a refund of $4,560 in 2010 as a result of the 2009 audit settlement recorded as a tax refund receivable in 2009. This was reflected in the effect of foreign tax line of the rate reconciliation in 2009.

A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:


	For the Years Ended December 31,
	2010			2009
Balance at beginning of period	$	78,811		$	84,554
Increase in unrecognized tax benefits resulting from tax positions taken during current period		15,998			17,461
Increase (decrease) in unrecognized tax benefits resulting from tax positions taken during prior period		(260	)		7,825
Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations		(3,200	)		(3,800	)
Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities		—			(27,229	)

Balance at end of period	$	91,349		$	78,811

If these unrecognized tax benefits were recognized $16,802 and $15,502 would affect CONSOL Energy’s effective income tax rate for the years ended December 31, 2010 and 2009, respectively.

During the year ended December 31, 2010, CONSOL Energy paid no federal and state income tax deficiencies.

The IRS is continuing 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, 2011. Any resulting tax deficiency or overpayment from the IRS examination 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, 2010 and 2009, the Company had an accrued liability of $10,774 and $8,338 respectively, for interest related to uncertain tax positions. The accrued interest liabilities include $2,436, $2,409 and $2,012 of interest expense that was recorded in the Company’s Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008, respectively. During the year ended December 31, 2010, CONSOL Energy did not pay or receive any interest related to income tax deficiencies or overpayments with the IRS.

CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2010 and 2009, 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

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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.

The reconciliation of changes in the asset retirement obligations at December 31, 2010 and 2009 is as follows:


	As of December 31,
	2010			2009
Balance at beginning of period	$	533,177		$	544,314
Accretion expense		46,200			39,610
Payments		(45,961	)		(31,458	)
Revisions in estimated cash flows		82,742			(19,006	)
Dominion Acquisition (Note 2)		62,098			—
Other		(7,400	)		(283	)

Balance at end of period	$	670,856		$	533,177

For the year ended December 31, 2010, Revisions in estimated cash flows include $80,525 related to additional reclamation liabilities recognized at the Fola mining operation in West Virginia. As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mine plans, the reclamation liability associated with the Fola operation was revised.

For the year ended December 31, 2010, Other includes ($7,400) for asset dispositions related to the sale of Jones Fork Mining Complex. See Note 24—Commitments and Contingent Liabilities for additional details. For the year ended December 31, 2009, Other includes ($283) of various other items, none of which are individually significant.

Note 8—Inventories:

Inventory components consist of the following:


	December 31,
	2010		2009
Coal	$	108,694	$	173,719
Merchandise for resale		50,120		44,842
Supplies		99,724		89,036

Total Inventories	$	258,538	$	307,597

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 $19,624 and $13,696 at December 31, 2010 and 2009, respectively.

Note 9—Accounts Receivable Securitization:

In April 2010, CONSOL Energy and certain of our U.S. subsidiaries amended their existing trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. The amended facility allows CONSOL Energy to receive on a revolving basis up to $200,000, a $35,000 increase over the previous facility. The amended facility also allows for the issuance of letters of credit against the $200,000 capacity. At December 31, 2010, there were no letters of credit outstanding against the facility.

CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, buys and sells eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility,

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CONSOL Energy and certain subsidiaries, irrevocably and without recourse, sell all of their eligible trade accounts receivable to CNX Funding Corporation, who in turn sells these receivables 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 a short average collection cycle for such receivables, our collection experience history and the composition of the designated pool of trade accounts receivable that are part of this program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable. CONSOL Energy will continue to service the sold trade receivables for the financial institutions for a fee based upon market rates for similar services.

Effective January 1, 2010, CONSOL Energy modified the reporting of the Accounts Receivable securitization facility transactions in the Consolidated Financial Statements. The modification includes reporting the pledge of collateral as Accounts Receivable—Securitized and the borrowings are now classified as debt in Borrowings under Securitization Facility.

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 $2,676 and $2,990 for the years ended December 31, 2010 and 2009, 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, 2010 and 2009, eligible accounts receivable totaled $200,000 and $151,000, respectively. There was no subordinated retained interest at December 31, 2010. There was subordinated retained interest of $101,000 at December 31, 2009. Accounts Receivable—Securitization and Borrowings under Securitization Facility of $200,000 and $50,000 were recorded on the Consolidated Balance Sheets at December 31, 2010 and 2009, respectively. Also, the $150,000 increase and $115,000 decrease in the accounts receivable securitization program for the year ended December 31, 2010 and 2009, respectively, is reflected in the Net Cash Provided By (Used In) Financing Activities in the Consolidated Statements of Cash Flows. In accordance with the facility agreement, the company is able to receive proceeds based upon the eligible accounts receivable at the previous month end.

Note 10—Property, Plant and Equipment:


	December 31,
	2010		2009
Coal and other plant and equipment	$	5,100,085	$	4,874,880
Unproven gas properties		2,206,399		284,065
Proven gas properties		1,662,605		186,135
Coal properties and surface lands		1,292,701		1,284,795
Intangible drilling cost		1,116,884		913,231
Gas gathering equipment		941,772		804,212
Airshafts		662,315		622,068
Mine development		587,518		573,037
Leased coal lands		536,603		504,475
Coal advance mining royalties		389,379		366,312
Gas wells and related equipment		367,448		251,045
Other gas assets		84,571		15,000
Gas advance royalties		3,078		2,700

Total Property, Plant and Equipment		14,951,358		10,681,955
Less—Accumulated depreciation, depletion and amortization		4,822,107		4,557,665

Net Property, Plant and Equipment	$	10,129,251	$	6,124,290

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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.

Coal reserves are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned and 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 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.

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 or development 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. Any material effect from changes in estimates is disclosed in the period the change occurs.

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, 2010 and 2009, respectively.


	December 31,
	2010		2009
Unproven gas properties	$	2,206,399	$	284,065
Coal properties		394,635		332,606
Leased coal lands		171,056		195,674
Airshafts		73,703		63,673
Coal advance mining royalties		67,674		39,730
Mine development		34,907		114,800
Gas advance royalties		2,800		2,405

Total	$	2,951,174	$	1,032,953

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As of December 31, 2010 and 2009, plant and equipment includes gross assets under capital lease of $88,859 and $81,770, respectively. For the years ended December 31, 2010 and 2009, 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, 2010 and 2009, the Gas segment also maintains a capital lease for vehicles of $5,919 and $2,788, respectively, which are included in Other gas assets. For the years ended December 31, 2010 and 2009, the All Other segment maintains capital leases for vehicles and computer equipment of $16,021 and $12,063, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was $30,251 and $21,893 at December 31, 2010 and 2009, respectively. Amortization expense for capital leases is included in depreciation expense. See Note 14—Leases for further discussion of capital leases.

Note 11—Short-Term Notes Payable:

On May 7, 2010, CONSOL Energy entered into a four-year $1,500,000 senior secured credit facility, which extends through May 7, 2014. It replaced a five-year $1,000,000 senior secured facility which extended through June 2012. The new 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. 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 2.00 to 1.00, measured quarterly. The interest coverage ratio was 4.54 to 1.00 at December 31, 2010. The facility includes a maximum leverage ratio covenant of not more than 4.75 to 1.00, measured quarterly. The maximum leverage ratio was 3.48 to 1.00 at December 31, 2010. The facility also includes a senior secured leverage ratio covenant of not more than 2.50 to 1.00, measured quarterly. The senior secured leverage ratio was 0.72 to 1.00 at December 31, 2010. 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, merge with another corporation and amend, modify or restate the senior unsecured or secured notes. At December 31, 2010, the $1,500,000 facility had $155,000 of borrowings outstanding and $266,656 of letters of credit outstanding, leaving $1,078,344 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 3.76% and 0.86% as of December 31, 2010 and 2009, respectively.

On May 7, 2010, CNX Gas entered into a four-year $700,000 senior secured credit facility, which extends through May 6, 2014. It replaced a five-year $200,000 unsecured credit agreement that extended through October 2010. The new facility is secured by substantially all of the assets of CNX Gas and its subsidiaries. Effective June 30, 2010, the assets acquired in the Dominion Acquisition have been merged into one entity and the shares of this entity have been transferred to CNX Gas, making it a wholly-owned subsidiary of CNX Gas. The acquired assets are now pledged as collateral under the CNX Gas senior secured credit agreement. Collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in 2012. 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, pay dividends and merge with another corporation. The facility includes a maximum leverage ratio covenant of not more than 3.50 to 1.00, measured quarterly. The maximum leverage ratio was 0.52 to 1.00 at December 31, 2010. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 69.60 to 1.00 at December 31, 2010. At December 31, 2010, the $700,000 facility had $129,000 of borrowings outstanding and $70,203 of letters of credit outstanding, leaving $500,797 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 2.26% and 1.69% as of December 31, 2010 and 2009, respectively.

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Note 12—Other Accrued Liabilities:


	December 31,
	2010		2009
Subsidence liability	$	83,751	$	72,390
Accrued interest		64,695		8,500
Accrued payroll and benefits		58,771		50,696
Accrued other taxes		56,839		42,559
Uncertain income tax positions		41,235		42,423
Short-term incentive compensation		38,474		35,710
Other		139,079		127,693
Current portion of long-term liabilities:
Postretirement benefits other than pensions		179,809		164,747
Mine closing		38,433		19,568
Gas well closing		27,919		—
Workers’ compensation		27,754		27,885
Reclamation		25,933		3,192
Pneumoconiosis benefits		10,915		9,676
Long term disability		6,126		5,468
Salary retirement		2,258		2,331

Total Other Accrued Liabilities	$	801,991	$	612,838

Note 13—Long-Term Debt:


	December 31,
	2010		2009
Debt:
Senior notes due April 2017 at 8.00%, issued at par value	$	1,500,000	$	—
Senior notes due April 2020 at 8.25%, issued at par value.		1,250,000		—
Secured notes due March 2012 at 7.875% (par value of $250,000 less unamortized discount of $242 and $447 at December 31, 2010 and 2009, respectively)		249,758		249,553
Baltimore Port Facility revenue bonds in series due September 2025 at 5.75%		102,865
Baltimore Port Facility revenue bonds in series due December 2010 at 6.50%		—		30,865
Baltimore Port Facility revenue bonds in series due October 2011 at 6.50%.		—		72,000
Advance royalty commitments (7.56% and 7.36% weighted average interest rate for December 31, 2010 and 2009, respectively)		32,211		35,547
Note due through December 2012 at 6.10%		10,438		14,628
Other long-term notes maturing at various dates through 2031		93		160

		3,145,365		402,753
Less amounts due in one year		16,629		39,024

Total Long-Term Debt	$	3,128,736	$	363,729

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Annual undiscounted maturities on long-term debt during the next five years are as follows:


Year Ended December 31,	Amount
2011	$	16,629
2012		258,998
2013		3,062
2014		2,720
2015		2,453
Thereafter		2,861,745

Total Long-Term Debt Maturities	$	3,145,607

In September 2010, CONSOL Energy refinanced $102,865 of industrial development bonds associated with its wholly-owned CNX Marine Terminal in the Port of Baltimore, Maryland. The refunding municipal bonds issued by the Maryland Economic Development Corporation mature on September 1, 2025 and carry an interest rate of 5.75%. The previous bonds carried an interest rate of 6.50% and were due to mature in December 2010 and October 2011.

On April 1, 2010, CONSOL Energy closed the offering of $1,500,000 of 8.00% senior notes which mature on April 1, 2017 and $1,250,000 of 8.25% senior notes which mature on April 1, 2020. The notes are guaranteed by substantially all of our existing wholly owned domestic subsidiaries. The proceeds from this offering were used to finance, in part, the Dominion Acquisition.

Notes due through 2012 represent the debt incurred by a variable interest entity in which CONSOL Energy holds no ownership interest, but is the primary beneficiary. CONSOL Energy has guaranteed the outstanding principal balance of this loan agreement between the variable interest entity and Huntington National Bank.

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, 2010, are as follows:


Year Ended December 31, 2010	Capital Leases		Operating Leases
2011	$	12,632	$	77,414
2012		10,692		62,311
2013		9,407		57,707
2014		8,275		47,248
2015		7,463		35,969
Thereafter		42,997		125,829

Total minimum lease payments	$	91,466	$	406,478

Less amount representing interest (0.75% - 7.36%)		25,910

Present value of minimum lease payments		65,556
Less amount due in one year		8,154

Total Long-Term Capital Lease Obligation	$	57,402

Rental expense under operating leases was $94,137, $77,960, and $63,170 for the years ended December 31, 2010, 2009 and 2008, respectively.

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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 year, settlement accounting is required. Lump sum payments did not exceed the threshold during 2010, 2009 or 2008.

Following the merger of the CNX Gas pension plan into the CONSOL Energy pension plan in 2009, a 2010 amendment was made to the pension plan to recognize past service at CNX Gas and extending coverage to employees previously not eligible. The prior service costs for these events have been reflected as Plan Amendments in the reconciliation of the change in benefit obligation for the year ended December 31, 2010. Additionally, during the year ended December 31, 2009, certain 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 change in benefit obligation for the year ended December 31, 2009.

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. Base eligibility is age 55 with 20 years of service. The salaried plan contains a medical cost sharing arrangement with all salaried employees and salaried retirees. These participants contribute a target of 20% of 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 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 $1.00 per each hour worked. In 2010, retiree medical benefits for salaried CNX Gas participants became consistent with the retiree medical benefits for CONSOL Energy salaried employees.

The OPEB liability at December 31, 2010 reflects an increase of $12,300 due to the Patient Protection and Affordable care Act (PPACA) reform legislation; in particular, the estimated impact of the potential excise tax beginning in 2018. A corresponding increase in Other Comprehensive Loss was also recognized. The estimated increase in the liability was calculated using the following assumptions: testing pre-Medicare and Medicare covered retirees on a combined basis; assuming individual participants have an average 2010 claim cost and future healthcare trend assumptions equal to those used in the year end valuation; assuming the 2018 tax threshold amount to increase for inflation in later years. These assumptions may change once additional guidance becomes available.

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The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2010 and 2009, is as follows:


	Pension Benefits at December 31,						Other Postretirement Benefits at December 31,
	2010			2009			2010			2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	654,022		$	571,772		$	2,844,093		$	2,638,773
Service cost		14,491			12,332			13,147			12,654
Interest cost		37,150			35,483			162,815			151,451
Actuarial loss		54,006			78,529			400,118			197,066
Plan amendments		682			3,371			204			—
Dominion Acquisition		900			—			2,800			—
Participant contributions		—			—			4,802			4,633
Benefits and other payments		(60,099	)		(47,465	)		(170,780	)		(160,484	)

Benefit obligation at end of period	$	701,152		$	654,022		$	3,257,199		$	2,844,093

Change in plan assets:
Fair value of plan assets at beginning of period	$	462,000		$	375,261		$	—		$	—
Actual return on plan assets		63,444			66,537			—			—
Company contributions		72,376			67,667			165,978			155,851
Participant contributions		—			—			4,802			4,633
Benefits and other payments		(60,099	)		(47,465	)		(170,780	)		(160,484	)

Fair value of plan assets at end of period	$	537,721		$	462,000		$	—		$	—

Funded status:
Noncurrent assets	$	—		$	6		$	—		$	—
Current liabilities		(2,258	)		(2,331	)		(179,809	)		(164,747	)
Noncurrent liabilities		(161,173	)		(189,697	)		(3,077,390	)		(2,679,346	)

Net obligation recognized	$	(163,431	)	$	(192,022	)	$	(3,257,199	)	$	(2,844,093	)

Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial loss	$	358,674		$	362,901		$	1,485,090		$	1,152,630
Prior service credit		(1,725	)		(3,141	)		(121,943	)		(168,561	)

Net amount recognized (before tax effect)	$	356,949		$	359,760		$	1,363,147		$	984,069

The components of net periodic benefit costs are as follows:


	Pension Benefits									Other Postretirement Benefits
	For the Years Ended December 31,									For the Years Ended December 31,
	2010			2009			2008			2010			2009			2008
Components of net periodic benefit cost:
Service cost	$	14,485		$	12,332		$	9,752		$	13,147		$	12,654		$	10,555
Interest cost		37,150			35,483			33,029			162,815			151,451			159,837
Expected return on plan assets		(36,977	)		(36,631	)		(33,671	)		—			—			—
Amortization of prior service cost (credit)		(735	)		(1,109	)		(1,114	)		(46,415	)		(46,415	)		(48,625	)
Recognized net actuarial loss		31,870			22,263			16,728			70,145			50,357			61,503

Benefit cost	$	45,793		$	32,338		$	24,724		$	199,692		$	168,047		$	183,270

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Amounts included in accumulated other comprehensive loss, expected to be recognized in 2011 net periodic benefit costs:


	Pension Benefits			Other Postretirement Benefits
Prior service cost (benefit) recognition	$	(666	)	$	(46,397	)
Actuarial loss recognition	$	36,583		$	89,457

The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan assets:


	As of December 31,
	2010		2009
Projected benefit obligation	$	701,152	$	653,925
Accumulated benefit obligation	$	629,433	$	580,498
Fair value of plan assets	$	537,721	$	462,000

Assumptions:

The weighted-average assumptions used to determine benefit obligations are as follows:


	Pension Benefits For the Year Ended December 31,						Other Postretirement Benefits For the Year Ended December 31,
	2010			2009			2010			2009
Discount rate		5.30	%		5.79	%		5.33	%		5.87	%
Rate of compensation increase		3.68	%		4.09	%		—			—

The weighted-average assumptions used to determine net periodic benefit costs are as follows:


	Pension Benefits at December 31,									Other Postretirement Benefits at December 31,
	2010			2009			2008			2010			2009			2008
Discount rate		5.79	%		6.28	%		6.57	%		5.87	%		6.20	%		6.63	%
Expected long-term return on plan assets		8.00	%		8.00	%		8.00	%		—			—			—
Rate of compensation increase		4.14	%		4.05	%		4.01	%		—			—			—

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,
	2010			2009			2008
Health care cost trend rate for next year		8.47	%		8.74	%		9.60	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)		4.50	%		4.50	%		5.00	%
Year that the rate reaches ultimate trend rate		2023			2023			2015

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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	$	20,663	$	(17,533	)
Effect on accumulated postretirement benefit obligation	$	400,475	$	(336,662	)

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	$	(1,569	)	$	1,583
Other postemployment benefits costs (decrease) increase	$	(4,060	)	$	4,779

Plan Assets:

The company’s overall investment strategy 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 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.

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The fair values of plan assets at December 31, 2010 and 2009 by asset category are as follows:


	Fair Value Measurements at December 31, 2010								Fair Value Measurements at December 31, 2009
	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets far Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Asset Category
Cash	$	482	$	482	$	—	$	—	$	231	$	231	$	—	$	—
US Equities (a)		2		2		—		—		3		3		—		—
MGI Collective Trusts
US Large Cap Growth Equity (b)		48,328		—		48,328		—		42,186				42,186		—
US Large Cap Value Equity (c)		48,802		—		48,802		—		41,205				41,205		—
US Small/Mid Cap Growth Equity (d)		20,580		—		20,580		—		17,069				17,069		—
US Small/Mid Cap Value Equity (e)		20,459		—		20,459		—		16,826				16,826		—
US Core Fixed Income (f)		27,660		—		27,660		—		17,755				17,755		—
Non-US Core Equity (g)		130,305		—		130,305		—		110,747				110,747		—
US Long Duration Investment Grade Fixed Income (h)		46,848		—		46,848		—		41,261				41,261		—
US Long Duration Fixed Income (i)		67,949		—		67,949		—		58,466				58,466		—
US Large Cap Passive Equity (j)		59,776		—		59,776		—		52,255				52,255		—
US Passive Fixed Income (k)		14,996		—		14,996		—		12,999				12,999		—
US Long Duration Passive Fixed Income (l)		26,796		—		26,796		—		23,589				23,589		—
US Ultra Long Duration Fixed Income (m)		24,738		—		24,738		—		27,408				27,408		—

Total	$	537,721	$	484	$	537,237	$		$	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 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 Value Index.

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(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 corporate 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 US 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.

(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 investments in CONSOL Energy stock held by these plans at December 31, 2010 or 2009.

There are no assets in the other postretirement benefit plans at December 31, 2010 or 2009.

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 2011. Pension benefit payments are primarily funded from the trust. CONSOL Energy does not expect to contribute to the other postemployment plan in 2011. We intend to pay benefit claims as they are due.

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The following benefit payments, reflecting expected future service, are expected to be paid:


	Pension Benefits		Other Benefits
2011	$	34,592	$	179,809
2012	$	39,468	$	186,613
2013	$	40,822	$	193,986
2014	$	42,975	$	201,158
2015	$	44,623	$	207,953
Year 2016-2020	$	270,514	$	1,098,793

Note 16—Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation:

The CWP liability was remeasured as of April 1, 2010 due to new legislation enacted in the Patient Protection and Affordable Care Act (PPACA). In general, the PPACA impacts CONSOL Energy’s liability in that future claims will be approved at a higher rate than has occurred in the past. The PPACA made two changes to the Federal Black Lung Benefits Act (FBLBA). First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in coal mines and suffer from totally disabling lung disease. A coal company would have to prove that a miner did not have black lung or that the disease was not caused at his/her work. Second, it changed the law so that black lung benefits being received by miners automatically go to their dependent survivors, regardless of cause of the miner’s death. The impact of the new law increased CONSOL Energy’s CWP liability by $45,700. The law change increased expense by $6,658 for the year ended December 31, 2010. In conjunction with the law change, CONSOL Energy conducted an extensive experience study regarding the rate of claim incidence. Based on historical company data and available industry data, with emphasis on recent history, certain assumptions were revised at the remeasurement date. Most notably, the expected number of claims, prior to the law change, was reduced to more appropriately reflect CONSOL Energy’s historical experience. The assumption and remeasurement changes resulted in a decrease in the liability of $47,700. The assumption and remeasurement changes reduced expense by $10,576 for the year ended December 31, 2010.

The combined impact of the changes in actuarial assumptions, remeasurement and changes to the FBLBA was a net decrease of $1,232 in liability, net of $768 tax, as well as Accumulated Other Comprehensive Income based on an April 1, 2010 remeasurement date. The combined impact of these changes reduced expense by $3,918 for the year ended December 31, 2010.

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’ 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 healthcare trend rate, benefit duration and recurrence

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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.


	CWP December 31,						Workers’ Compensation December 31,
	2010			2009			2010			2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	194,641		$	200,094		$	179,268		$	159,761
State administrative fees and insurance bond premiums		—			—			7,816			6,710
Service, legal and administrative cost		8,067			9,774			30,399			31,795
Interest cost		10,789			12,054			9,156			8,765
Actuarial (gain) loss		(17,381	)		(16,584	)		(14,553	)		9,825
Benefits paid		(11,585	)		(10,697	)		(37,630	)		(37,588	)

Benefit obligation at end of period	$	184,531		$	194,641		$	174,456		$	179,268

Current liabilities .	$	(10,915	)	$	(9,676	)	$	(27,754	)	$	(27,885	)
Noncurrent liabilities		(173,616	)		(184,965	)		(146,702	)		(151,383	)

Net obligation recognized	$	(184,531	)	$	(194,641	)	$	(174,456	)	$	(179,268	)

Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial gain	$	(178,772	)	$	(184,666	)	$	(56,358	)	$	(45,232	)
Prior service credit		(1,123	)		(1,851	)		—			—

Net amount recognized (before tax effect)	$	(179,895	)	$	(186,517	)	$	(56,358	)	$	(45,232	)

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,
	2010			2009			2008			2010			2009			2008
Components of Net Periodic Cost (Credit):
Service cost	$	5,067		$	7,074		$	5,036		$	27,015		$	28,394		$	29,030
Interest cost		10,789			12,054			11,748			9,156			8,765			8,328
Legal and administrative costs		3,000			2,700			2,700			3,384			3,401			3,224
Amortization of prior service cost		(728	)		(728	)		(728	)		—			—			—
Recognized net actuarial gain		(21,585	)		(19,590	)		(23,383	)		(3,072	)		(4,200	)		(4,938	)
State administrative fees and insurance bond premiums		—			—			—			7,816			6,710			5,509

Net periodic cost (credit)	$	(3,457	)	$	1,510		$	(4,627	)	$	44,299		$	43,070		$	41,153

Amounts included in accumulated other comprehensive income, expected to be recognized in 2011 net periodic benefit costs:


	CWP Benefits			Workers’ Compensation Benefits
Prior service benefit recognition	$	(728	)	$	—
Actuarial gain recognition	$	(21,182	)	$	(3,907	)

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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,
	2010			2009			2008			2010			2009			2008
Benefit obligations		5.21	%		5.84	%		6.23	%		5.13	%		5.55	%		5.90	%
Net Periodic (benefit) costs		5.84	%		6.23	%		6.62	%		5.55	%		5.90	%		5.94	%

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	$	(634	)	$	606
Workers’ Compensation costs (decrease) increase	$	(725	)	$	762

Cash Flows:

CONSOL Energy does not intend to make contributions to the CWP or Workers’ Compensation plans in 2011. 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:


	CWP Benefits		Workers’ Compensation
	CWP Benefits		Total Benefits		Actuarial Benefits		Other Benefits
2011	$	10,915	$	36,272	$	27,754	$	8,518
2012	$	11,360	$	36,608	$	27,877	$	8,731
2013	$	11,714	$	37,215	$	28,266	$	8,949
2014	$	11,991	$	37,867	$	28,694	$	9,173
2015	$	12,196	$	38,594	$	29,192	$	9,402
Year 2016-2020	$	62,130	$	205,661	$	155,005	$	50,656

Note 17—Other Employee Benefit Plans:

UMWA 1974 Pension Trust:

Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan (1974 Pension Trust) negotiated with the United Mine Workers of America (UMWA) and contained in the National Bituminous Coal Wage Agreement (NBCWA). The 1974 Pension Trust is overseen by a board of trustees, consisting of two union-appointed trustees and two employer-appointed trustees. The trustees’ responsibilities include selection of the plan’s investment policy, asset allocation, individual investment of plan assets and the administration of the plan. The benefits provided by the 1974 Pension Trust to the participating employees are determined based on age and years of service at retirement. The current 2007 NBCWA will expire on December 31, 2011 and calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The contribution rates called for by the current NBCWA are: $3.50 per hour worked in 2008; $4.25 per hour worked in 2009, $5.00 per hour worked in 2010 and $5.50 per hour worked in 2011. For the plan year ended June 30, 2010, approximately 18% of retirees and surviving spouses receiving benefits from the 1974 Pension Trust last worked at signatory subsidiaries of CONSOL Energy.

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For the plan year ended June 30, 2010, approximately 30% of contributions made to the 1974 Pension Trust came from certain signatory subsidiaries of CONSOL Energy. Total contributions made by signatory subsidiaries of CONSOL Energy to the UMWA 1974 Pension Trust were $31,591, $25,620 and $21,140, for the years ended December 31, 2010, 2009 and 2008, respectively. These multi-employer pension plan contributions are expensed as incurred. 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. CONSOL Energy expects its signatory subsidiaries to contribute approximately $32,000 to the 1974 Pension Trust in 2011. Contributions to this multi-employer pension plan could increase as a result of future collective bargaining with the UMWA, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute to the 1974 Pension Trust, lower than expected returns on pension assets or other funding deficiencies. Contribution rates for the 1974 Pension Trust required beyond December 31, 2011, cannot be estimated at this time.

Certain subsidiaries of CONSOL Energy face risks and uncertainties by participating in the 1974 Pension Trust. All assets contributed to the plan are pooled and available to provide benefits for all participants and beneficiaries. As a result, contributions made by signatory subsidiaries of CONSOL Energy benefit employees of other employers. If the 1974 Pension Trust fails to meet ERISA’s minimum funding requirements or fails to develop and adopt a rehabilitation plan, a nondeductible excise tax of five percent of the accumulated funding deficiency may be imposed on an employer’s contribution to this multi-employer pension plan. On October 7, 2010, certain subsidiaries of CONSOL Energy received notice from the trustees of the 1974 Pension Trust stating that the plan is considered to be “seriously endangered” for the plan year beginning July 1, 2010. Under the Pension Protection Act (Pension Act), a funded percentage of 80% should be maintained for this multi-employer pension plan, and if the plan is determined to have a funded percentage 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. As a result of the 1974 Pension Trust’s “seriously endangered” status, steps must be taken under the Pension Act to improve the funded status of the plan. These steps could result in requiring certain signatory subsidiaries of CONSOL Energy to make additional contributions pursuant to a funding improvement plan adopted and implemented in accordance with the Pension Act and, therefore, could have a material impact on our operating results.

Under current law governing multi-employer defined benefit plans, if certain signatory subsidiaries of CONSOL Energy voluntarily withdrawal from the 1974 Pension Trust, the currently underfunded multi-employer defined benefit plan would require the withdrawing subsidiaries to make payments to the plan, which payments would approximate the proportionate share of the multiemployer plan’s unfunded vested benefit liabilities at the time of the withdrawal. The 1974 Pension Trust uses a modified “rolling five” method for calculating an employer’s share of the unfunded vested benefits, or the withdrawal liability, for a plan year. An employer would be obligated to pay its pro-rata share of the unfunded vested benefits based on the ratio of hours worked by the employer’s employees during the previous five plan years for which contributions were due compared to the number of hours worked by all the employees of the employers from which contributions were due. The 1974 Pension Trust’s unfunded vested benefits at June 30, 2010, the end of the latest plan year, were $4,152,806. CONSOL Energy’s signatory subsidiaries’ percentage of hours worked compared to the total hours worked by all plan participants was estimated to be approximately 30%. If certain of CONSOL Energy subsidiaries were to withdrawal from the 1974 Pension Trust, they may be required to make collective, annual payments of approximately $35,000 to $40,000 per year for a period of at least 20 years. The estimated present value of the payment stream could result in a liability of $375,000 to $475,000.

UMWA Benefit Trusts:

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.

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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 $19,904, $22,646, and $24,343 for the years ended December 31, 2010, 2009 and 2008, respectively. Based on available information at December 31, 2010, CONSOL Energy’s obligation for the Act is estimated at approximately $148,152.

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 $1.42 per hour worked by UMWA represented employees for the year ended December 31, 2010, comprised of a $0.50 per hour worked under the labor agreement and $0.92 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 $1.44 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 2006 Act. The contribution rate for the year ended December 31, 2008, was $1.77 per hour worked by UMWA represented employees, comprised of $0.50 per hour worked under the labor agreement and $1.27 per hour worked under the 2006 Act. Total contributions were $9,212, $9,072 and $11,494 for the years ended December 31, 2010, 2009 and 2008, 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 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 $67,768 and $61,734 for years ended December 31, 2010 and 2009, respectively. The 2010 and 2009 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, 2010, approximately 34% 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—Stock Based Compensation for further discussion of CONSOL Energy’s equity incentive plans.

On June 1, 2010, CONSOL Energy completed the acquisition of CNX Gas Corporation (CNX Gas) outstanding common stock pursuant to a tender offer followed by a short-form merger in which CNX Gas became a wholly owned subsidiary. As a result of this acquisition, CNX Gas no longer has its own independent equity incentive plan. Prior to the acquisition, the CNX Gas equity incentive plan consisted 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 could be granted under CNX Gas’ plan was 2,500,000. CNX Gas stock-based compensation expense resulted in pre-tax expense of $2,043, $6,311 and $3,379 for the years ended December 31, 2010, 2009 and 2008, respectively.

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Long Term Incentive Compensation:

Prior to the acquisition of CNX Gas, as discussed above, 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 at the program vesting date. 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 of compensation costs was recognized for the year ended December 31, 2008. A credit to expense of approximately $1,434 was recognized during 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 removed from the Consolidated Balance Sheets of CONSOL Energy. As a result of the completed exchange offer there were 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. Total payments and costs were $27,221, $24,353, and $23,091 for the years ended December 31, 2010, 2009 and 2008, 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,
	2010			2009			2008
Benefit Costs	$	3,294		$	3,642		$	3,998
Discount rate assumption used to determine Net periodic benefit obligations		4.72	%		5.92	%		5.92	%

Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities—Other and Other Accrued Liabilities and amounted to $36,233 and $30,097 at December 31, 2010 and 2009, 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 to 23,800,000. At December 31, 2010, 3,594,331 shares are available for all awards. The Plan, as amended, provides that the aggregate number of shares available for

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issuance under the Plan will be reduced by one share for each share issued in settlement of stock options and by 1.44 for each share issued in settlement of Performance Share Units (PSUs) or Restricted Stock Units (RSUs) 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.

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 $45,550, $32,723 and $21,807 for the years ended December 31, 2010, 2009 and 2008, respectively. The related deferred tax benefit totaled $17,473, $12,490 and $8,293, for the years ended December 31, 2010, 2009 and 2008, 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 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, 2010, 2009 and 2008 were $10,361, $9,950 and $11,395, 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,
	2010			2009			2008
Weighted average fair value of grants	$	21.97		$	14.48		$	29.44
Risk-free interest rate		1.88	%		1.45	%		2.59	%
Expected dividend yield		0.80	%		1.40	%		0.50	%
Expected forfeiture rate		2.00	%		2.00	%		2.00	%
Expected volatility		59.00	%		75.60	%		46.60	%
Expected term in years		4.04 years			4.10 years			3.97 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, 2009		5,387,141		$	26.86
Granted		471,494		$	49.63
Exercised		(388,928	)	$	15.42
Forfeited		(16,466	)	$	47.61

Balance at December 31, 2010		5,453,241		$	29.59		5.07	$	116,059

Vested and expected to vest		5,444,006		$	29.54		5.09	$	116,054

Exercisable at December 31, 2010		4,433,084		$	26.34		4.31	$	106,558

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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 4,961,199 stock options outstanding under the Equity Incentive plan. Additionally, there are 401,953 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 90,089 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, 2010, and 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, 2010. 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, 2010, 2009 and 2008 was $10,722, $4,502 and $55,131, respectively.

Cash received from option exercises for the years ended December 31, 2010, 2009 and 2008 was $5,993, $2,547 and $15,215, respectively. The excess tax benefit realized for the tax deduction from option exercises totaled $15,365, $3,270, and $22,003, for the years ended December 31, 2010, 2009 and 2008, 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, 2010, 2009 and 2008 were $28,762, $42,720 and $5,950, respectively. The total fair value of shares vested during the years ended December 31, 2010, 2009 and 2008 was $22,244, $18,092 and $4,720, 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, 2009		1,294,377		$	31.15
Granted		638,735		$	45.03
Vested		(720,404	)	$	30.88
Forfeited		(44,264	)	$	38.41

Nonvested at December 31, 2010		1,168,444		$	38.63

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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, 2010, 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, 2010, 2009 and 2008 were $8,882, $5,684 and $4,904. 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, 2009		291,063		$	47.50
Granted		156,905		$	56.61
Vested		(109,955	)	$	42.50

Nonvested at December 31, 2010		338,013		$	53.36

Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance stock options. These awards entitle the holder to receive shares of common stock subject to the achievement of certain performance goals. Compensation expense will be recognized over the vesting period of the units. At December 31, 2010, achievement of the performance goals is believed to be probable. The total fair value of performance share options granted during the year ended December 31, 2010 were $13,198. The following represents the unvested performance options 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, 2009		—
Granted		802,804	$	16.44

Nonvested at December 31, 2010		802,804	$	16.44

As of December 31, 2010, $35,971 of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.78 years. When employee stock options are exercised and restricted and performance stock 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—Significant Accounting Policies.

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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, 2007	$	340		$	5,864		$	(424,352	)	$	(1,136	)	$	(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			124,510			(564,744	)		(21,929	)		(461,900	)
Net increase in value of cash flow hedges		—			185,862						(31,162	)		154,700
Reclassification of cash flow hedges from other comprehensive income to earnings		—			(238,994	)		—			40,024			(198,970	)
Current period change		(83	)		—			(134,549	)		298			(134,334	)

Balance at December 31, 2009	$	180			71,378			(699,293	)		(12,769	)		(640,504	)
Net increase in value of cash flow hedges					141,016			—			(12,476	)		128,540
Reclassification of cash flow hedges from other comprehensive income to earnings		—			(166,307	)		—			7,224			(159,083	)
Elimination of noncontrolling interest from purchase of CNX Gas					—			—			18,026			18,026
Current period change		(84	)					(221,228	)		(5	)		(221,317	)

Balance at December 31, 2010	$	96		$	46,087		$	(920,521	)	$	—		$	(874,338	)

The cash flow hedges that CONSOL Energy holds are disclosed in Note 23—Derivative Instruments. The adjustments for Actuarially Determined Liabilities are disclosed in Note 15—Pension and Other Postretirement Benefit Plans and Note 16—Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation.

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Note 20—Supplemental Cash Flow Information:


	For the Years Ended December 31,
	2010			2009			2008
Cash paid during the year for:
Interest (net of amounts capitalized)	$	152,155		$	26,425		$	33,236
Income taxes	$	118,550		$	131,043		$	95,101
Non-cash investing and financing activities:
Businesses acquired (Note 2)
Fair value of assets acquired	$	(72,772	)	$	28,113		$	(26,892	)
Liabilities assumed	$	(72,772	)	$	28,113		$	(26,892	)
Sale of assets due to litigation settlement (Note 2)
Change in Assets	$	7,400		$	—		$	—
Change in Liabilities	$	7,400		$	—		$	—
Amount withheld to cover taxes from stock-based compensation	$	19,581		$	8,145		$	1,754
Note received from property sales	$	—		$	(1,789	)	$	—
Capital Lease Obligation
Change in Assets	$	(7,158	)	$	(3,375	)	$	2,622
Change in Liabilities	$	(7,158	)	$	(3,375	)	$	2,622
Purchase of Property, Plant and Equipment
Change in Assets	$	13,969		$	46,938		$	(75,818	)
Change in Liabilities	$	13,969		$	46,938		$	(75,818	)
Accounting for Mine Closing, Reclamation and Gas Well Closing Costs
Change in Assets	$	(19,025	)	$	283		$	(29,088	)
Change in Liabilities	$	(19,025	)	$	283		$	(29,088	)

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, 2010 and 2009, accounts receivable from utilities were $220,052 and $215,630, respectively. As of December 31, 2010 and 2009, accounts receivable from steel and coke producers were $69,470 and $43,448, respectively. Accounts receivable from utilities and steel and coke producers include amounts sold under the accounts receivable securitization facility. See Note 9—Accounts Receivable Securitization for further discussion. As of December 31, 2010 and 2009, accounts receivable from coal brokers and distributors were $54,996 and $19,382, respectively. As of December 31, 2010 and 2009, accounts receivable from gas wholesalers were $65,358 and $43,534, 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, 2010, 2009 and 2008, no customer comprised over 10% of our revenues.

Note 22—Fair Value of Financial Instruments:

The financial instruments measured at fair value on a recurring basis are summarized below:


	Fair Value Measurements at December 31, 2010						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)		Quoted Prices in Active Markets far Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow hedges	$	—	$	76,240	$	—	$	—	$	117,483	$	—

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The following methods and assumptions were used to estimate the fair value for 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.

Restricted cash: The carrying amount reported in the balance sheets for restricted cash 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.

Borrowings under securitization facility: The carrying amount reported in the balance sheets for borrowings under the securitization facility 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, 2010						December 31, 2009
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	32,794		$	32,794		$	65,607		$	65,607
Restricted cash	$	20,291		$	20,291		$	—		$	—
Short-term notes payable	$	(284,000	)	$	(284,000	)	$	(472,850	)	$	(472,850	)
Borrowings under securitization facility	$	(200,000	)	$	(200,000	)	$	(50,000	)	$	(50,000	)
Long-term debt	$	(3,145,365	)	$	(3,341,406	)	$	(402,753	)	$	(420,056	)

Note 23—Derivative Instruments:

CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. 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 period. 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.

CONSOL Energy has entered into swap contracts for natural gas to manage the price risk associated with the forecasted natural gas revenues. The objective of these hedges is to reduce the variability of the cash flows

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associated with the forecasted revenues from the underlying commodity. As of December 31, 2010, the total notional amount of the Company’s outstanding natural gas swap contracts was 78.2 billion cubic feet. These swap contracts are forecasted to settle through December 31, 2014 and meet the criteria for cash flow hedge accounting. During the next year, $29,519 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, 2010, CONSOL Energy did not have any outstanding coal sales options. For the year ended December 31, 2009 and 2008, CONSOL Energy recognized, in Other Income on the Consolidated Statements 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 at December 31, 2010 of CONSOL Energy’s derivative instruments, which were all natural gas swaps and qualify for hedging, were an asset of $79,960 and a liability of $3,720. The total asset is comprised of $52,022 and $27,938 which were included in Prepaid Expense and Other Assets on the Consolidated Balance Sheets. The total liability is comprised of $3,191 and $529 which were included in Other Accrued Liabilities and Other Liabilities on the Consolidated Balance Sheets.

The effect of derivative instruments on the Consolidated Statements of Income for the year ended December 31, 2010 is as follows:


Derivative in Cash Flow Hedging Relationship	Amount of Gain Recognized in OCI on Derivative 2010		Location of Gain Reclassified from Accumulated OCI into Income		Amount of Gain Reclassified from Accumulated OCI into Income 2010		Location of Gain Recognized in Income on Derivative		Amount of Gain Recognized in Income on Derivative 2010
Natural Gas Price Swaps	$	141,016		Outside Sales	$	166,276		Outside Sales	$	31

Total	$	141,016			$	166,276			$	31

The fair value at December 31, 2009 of CONSOL Energy’s derivative instruments, which were all natural gas swaps and qualify for hedging, were an asset of $117,483. The total asset is comprised of $99,265 and $18,218, which were included in Prepaid Expense and Other Assets on the Consolidated Balance Sheets. There were no liability derivative instruments as of December 31, 2009.

The effect of derivative instruments on the Consolidated Statements of Income for the year ended December 31, 2009 is as follows:


Derivative in Cash Flow Hedging Relationship	Amount of Gain Recognized in OCI on Derivative 2009		Location of Gain Reclassified from Accumulated OCI into Income		Amount of Gain Reclassified from Accumulated OCI into Income 2009		Location of (Loss) Recognized in Income on Derivative		Amount of (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	)

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

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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, individually and in the aggregate, may be material to the financial position, results of operations or cash flows of CONSOL Energy.

Ryerson Dam Litigation: In 2008, the Pennsylvania Department of Conservation and Natural Resources (the 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 at its Bailey Mine caused cracks and seepage damage to the Ryerson Park Dam. The Commonwealth subsequently breached the 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 Commonwealth then filed a subsidence-damage claim with the Pennsylvania Department of Environmental Protection (DEP) and DEP reviewed the issue of whether the dam was damaged by subsidence. On February 16, 2010, DEP issued its interim report, concluding that the alleged damage was subsidence related. In the next phase of the DEP proceeding, which was the damage phase, DEP determined that the Company must repair the dam. The DEP estimated the cost of repair to be approximately $20,000. The Company has appealed DEP’s findings to the Pennsylvania Environmental Hearing Board (PEHB), which will consider the case de novo, meaning without regard to the DEP’s decision, as to any finding of causation of damage and/or the amount of damages. In order to perfect its appeal to the PEHB under the applicable statute, the Company deposited $20,291 into escrow as security for the DEP’s estimated cost of repair. This amount is reflected as restricted cash on the Consolidated Balance Sheets at December 31, 2010. The Company is seeking to substitute an appeal bond for the cash deposit. Either party may appeal the decision of the PEHB to the Pennsylvania Commonwealth Court, and then, as may be allowed, to the Pennsylvania Supreme Court. 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.

Asbestos-Related Litigation: One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 22,500 asbestos-related claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi, New Jersey, Texas 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.

Ward Transformer Superfund Site: CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under the Superfund program established by the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), 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

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CONSOL Energy was originally named a PRP, including payment of the EPA’s past and future cost, is approximately $65,000. The current estimated cost of the most likely remediation plan for the additional areas discovered is approximately $11,000. 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 $3,502, $3,422, and $7,080 of expense recognized in cost of goods sold and other charges in the years ended December 31, 2010, 2009 and 2008 respectively. CONSOL Energy funded $1,209, $5,500, and $6,000 in the years ended December 31, 2010, 2009 and 2008, respectively, to an independent trust established for this remediation. As of December 31, 2010, 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 incurred and to be incurred to conduct the removal actions at the Ward Site. CONSOL Energy’s portion of recoveries from settled claims is $4,173. Accordingly, the liability reflected in Other Accrued Liabilities was reduced by these settled claims. The remaining net liability at December 31, 2010 is $4,037.

Buchanan Mine Water Litigation: 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 (collectively, Yukon) filed an action on March 22, 2004 against CCC 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 were 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, and to recover over $3,252,000 for alleged damages to the coal and gas estates and punitive damages in the amount of $350. Plaintiffs also asserted damage claims of $150,000 against CONSOL Energy, CNX Gas Company, LLC and ICCC. The Yukon group also filed a demand for arbitration against ICCC which made similar claims relating to breach of the lease for water deposits and lost coal claims. All of the foregoing claims were settled in June 2010. Under the settlement agreement, CONSOL Energy paid Yukon (i) $25,000 in damages associated with the litigation; (ii) $30,000 to purchase certain of Yukon’s coal interests in the Pocahontas No. 3 coal seam, and rights appurtenant thereto, near the Buchanan Mine; and (iii) $20,000 in advance royalties on the remaining Pocahontas No. 3 coal owned by Yukon and leased to ICCC and which CCC intends to mine as part of the Buchanan Mine in the future, provided, that this payment will be recoupable against future royalties only after $20,000 in future production royalties has been paid to Yukon on the production of such coal. The settlement agreement included a release by Yukon of all claims against CONSOL Energy arising out of the deposit of water in the mine voids at issue in the litigation and other customary terms. The settlement agreement also required Yukon to withdraw its pending objection’s to CCC’s permit to discharge water from the Buchanan Mine into the Levisa River. Separately, in December 2010, we reached a tentative agreement with another party to settle a similar claim with respect to water stored in the VP-3 mine void. Under that agreement, we would pay $2,150, agree to exchange coal properties and agree to certain modifications of the lease, in exchange for the third party claimant’s release of all damages, consent to water storage and release of future lost coal claims.

South Carolina Gas & Electric Company Arbitration: 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 was scheduled for January 2011, but was continued generally, without a new hearing date being scheduled; the hearing will likely occur within the next six months. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them.

Northern Appalachia Water Issues: In the Fall of 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 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

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chlorides that cause Dunkard Creek to exceed West Virginia in-stream water quality standards. Prior to the fish kill and continuing thereafter, CCC was subject to an Agreed Order with the West Virginia Department of Environmental Protection (WVDEP) that set forth a schedule for compliance with these in-stream chloride limits. On December 18, 2009, the WVDEP issued a Unilateral Order that imposed additional conditions on CCC’s discharges into Dunkard Creek and required CCC to develop a plan for long-term treatment of those and other high-chloride discharges. Pursuant to the Unilateral Order as well as a subsequent Unilateral Order issued by the WVDEP, CCC submitted a plan and schedule to WVDEP which provides for construction of a centralized advanced technology mine water treatment plant by May 31, 2013 to achieve compliance with chloride effluent limits and in-stream chloride water quality standards. The cost of the treatment plant and related facilities may reach or exceed $200,000. Additionally, CCC has negotiated a joint Consent Decree with the U.S. Environmental Protection Agency (EPA) and the WVDEP that includes a compliance plan and schedule. The Consent Decree, which has not yet been finalized, is also likely to include a civil penalty to settle alleged past violations related to chlorides, without any admission of liability. The Consent Decree is likely to be finalized in the first quarter of 2011. In order to avoid litigation, CCC is also negotiating with the WVDEP and the West Virginia Department of Natural Resources to settle state claims for natural resource damages, without any admission of liability. This settlement is not expected to have a material impact to the financial position, results of operations or cash flows of CONSOL Energy.

CNX Gas Shareholders Litigation: CONSOL Energy has been named as a defendant in five putative class actions brought by alleged shareholders of CNX Gas challenging the tender offer by CONSOL Energy to acquire all of the shares of CNX Gas common stock that CONSOL Energy did not already own for $38.25 per share. The two cases filed in Pennsylvania Common Pleas Court have been stayed and the three cases filed in the Delaware Chancery Court have been consolidated under the caption In Re CNX Gas Shareholders Litigation (C.A. No. 5377-VCL) with one exception, these cases also name CNX Gas and certain officers and directors of CONSOL Energy and CNX Gas as defendants. All five actions generally allege that CONSOL Energy breached and/or aided and abetted in the breach of fiduciary duties purportedly owed to CNX Gas public shareholders, essentially alleging that the $38.25 price that CONSOL Energy paid to CNX Gas shareholders in the tender offer and subsequent short-form merger was unfair. Among other things, the actions seek a permanent injunction against or rescission of the tender offer, damages, and attorneys’ fees and expenses. The Delaware Court of Chancery denied an injunction against the tender offer and CONSOL Energy completed the acquisition of the outstanding shares of CNX Gas on June 1, 2010. The Delaware Court of Chancery certified to the Delaware Supreme Court the question of what legal standard should be applied to the tender offer, which would effectively determine whether the shareholders can proceed with a damage claim. The Delaware Supreme Court declined to accept the appeal pending a final judgment. Therefore, the lawsuit will likely go to trial, possibly later in 2011. CONSOL Energy believes that these actions are without merit and intends to defend them vigorously.

Comer Litigation: A class action lawsuit was filed on April 21, 2006 in U.S. District Court for the Southern District of Mississippi styled Comer v. CONSOL Energy, et. al. The suit names numerous energy producers, chemical manufacturers, and public utilities as defendants. The action is a claim for alleged enhanced damages suffered in Hurricane Katrina due to global warming allegedly due to the defendants’ contribution to greenhouse gases in the environment. The trial court dismissed the case and plaintiffs appealed. The appellate court reversed and the defendants sought rehearing en banc. Rehearing en banc was granted, but a number of judges recused themselves and there was no longer a quorum. As a result, the trial court’s dismissal was reinstated. The plaintiffs sought a Writ of Mandamus from the U.S. Supreme Court, which the Supreme Court denied. As a result, it is likely that this litigation is over.

Hale Litigation: A purported class action lawsuit was filed on September 23, 2010 in U.S. District Court in Abingdon, Virginia styled Hale v. CNX Gas Company LLC et. al. The lawsuit alleges that the plaintiff class consists of oil and gas owners, that the Virginia Supreme Court has decided that coalbed methane (CBM) belongs to the owner of the oil and gas estate, that the Virginia Gas and Oil Act of 1990 unconstitutionally allows force pooling of CBM, that the Act unconstitutionally provides only a 1/8 royalty to CBM owners for gas produced under the force pooling orders, and that the Company only relied upon control of the coal estate in

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force pooling the CBM notwithstanding the Virginia Supreme Court decision holding that if only the coal estate is controlled, the CBM is not thereby controlled. The lawsuit seeks a judicial declaration of ownership of the CBM and that the entire net proceeds of CBM production (that is, the 1/8 royalty and the 7/8 of net revenues since production began) be distributed to the class members. The Magistrate Judge issued a Report and Recommendation in which she recommends that the District Judge decide that the deemed lease provision of the Gas and Oil Act is constitutional as is the 1/8 royalty, and that CNX Gas need not distribute the net proceeds to class members. The Magistrate Judge recommended against the dismissal of certain other claims, none of which are believed to have any significance. CONSOL Energy believes that the case is without merit and intends to defend it vigorously.

Addison Litigation: A purported class action lawsuit was filed on April 28, 2010 in Federal court in Virginia styled Addison v. CNX Gas Company LLC. The case involves two primary claims: (i) the plaintiff and similarly situated CNX Gas lessors identified as conflicting claimants during the force pooling process before the Virginia Gas and Oil Board are the owners of the CBM and, accordingly, the owners of the escrowed royalty payments being held by the Commonwealth of Virginia; and (ii) CNX Gas failed to either pay royalties due these conflicting claimant lessors or paid less than required because of the alleged practice of improper below market sales and/or taking alleged improper post-production deductions. Plaintiffs seek a declaratory judgment regarding ownership and compensatory and punitive damages for breach of contract; conversion; negligence (voluntary undertaking), for force pooling coal owners after the Ratliff decision declared coal owners did not own the CBM; negligent breach of duties as an operator; breach of fiduciary duties; and unjust enrichment. CONSOL Energy believes that the case is without merit and intends to defend it vigorously.

Hall Litigation: A purported class action lawsuit was filed on December 23, 2010 styled Hall v. CONSOL Gas Company in Allegheny County Pennsylvania Common Pleas Court. The named plaintiff is Earl D. Hall. The purported class plaintiffs are all Pennsylvania oil and gas lessors to Dominion Exploration and Production Company, whose leases were acquired by CONSOL Energy. The complaint alleges more than 1,000 similarly situated lessors. The lawsuit alleges that CONSOL Energy incorrectly calculated royalties by (i) calculating line loss on the basis of allocated volumes rather than on a well-by-well basis, (ii) possibly calculating the royalty on the basis of an incorrect price, (iii) possibly taking unreasonable deductions for post-production costs and costs that were not arms-length, and (iv) not paying royalties on oil production. The complaint also alleges that royalty statements were false and misleading. The complaint seeks damages, interest and an accounting on a well-by-well basis. CONSOL Energy believes that the case is without merit and intends to defend it vigorously.

Fola Reclamation Liabilities: As a result of market conditions, permitting issues, new regulatory requirements and resulting changes in mining plans, the reclamation liability associated with the Fola mining operations in West Virginia has increased. Changes in mining plans have increased the quantity of material required to reclaim the disturbed area. A detailed reclamation plan has been developed and the definitive costs associated with the increased reclamation have been estimated. As a result, $80,525 of expense was recognized in Costs of Goods Sold and Other Operating Charges the year ended December 31, 2010.

GeoMet Litigation: On February 14, 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 alleged, among other things, that the defendants have violated the Virginia Antitrust Act in their dealings with GeoMet in southwest Virginia. The complaint, as amended, sought injunctive relief, compensatory damages of $385,600 and treble damages. In April 2010, CNX Gas and GeoMet entered into an agreement involving the exchange of less than eight hundred acres of coalbed methane rights in Virginia and the grant by Consolidation Coal Company to GeoMet of consent to stimulate the coal seam on certain of GeoMet’s drilling units in Virginia. This litigation was settled as part of that transaction. CNX Gas did not pay any amount to GeoMet in connection with the settlement of this litigation.

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Kennedy Litigation: The Company is a party to a case filed on March 26, 2008 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 removing CNX Gas 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. Both Plaintiffs and CNX Gas filed and argued motions for summary judgment; a decision on the motions has not been issued. CNX Gas believes this lawsuit to be without merit and intends to vigorously defend it.

Severance Tax Litigation: In April 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 subsequently filed three substantially similar cases for the years 2003, 2004 and 2005. These cases were consolidated. The complaint alleged 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 filed a claim for a refund for these years. Since 2002, we continued to pay Buchanan County taxes based on our method of calculating the taxes. This matter was settled on February 2, 2010. Under the terms of the settlement, among other things, CNX Gas agreed to pay an amount to Buchanan County, the present value of which was previously accrued and Buchanan County agreed to certain deductions for post-production costs in the calculation of the license tax for periods after January 1, 2010, which will reduce our costs in the future. In January 2011, Tazewell County asserted a similar claim for tax year 2007, although the County has not yet filed a lawsuit. CONSOL Energy is evaluating the merits of that claim.

Decker/Gillingham Litigation: Two contractor employees—Messrs. Decker and Gillingham—were injured when a stairway affixed to the exterior of a building collapsed at CONSOL Energy’s Research and Development facility in Allegheny County, Pennsylvania in 2007. Mr. Decker sustained a broken hip and leg. Mr. Gillingham sustained a torn rotator cuff. Both men have recovered and are working, although both claim that the accident has limited their ability to perform their jobs. Messrs. Decker and Gillingham sued CONSOL Energy on June 4, 2008 and June 20, 2008, respectively, in Allegheny County Common Pleas Court, alleging, among other things, that CONSOL Energy was negligent in the maintenance of the stairway. The cases were consolidated. In late November, 2010, after a jury trial, the jury found that CONSOL Energy was negligent in maintaining the stairway and the jury awarded Mr. Decker and his spouse $5,000 and Mr. Gillingham and his spouse $2,800. These amounts included compensatory damages, as well as damages for pain and suffering, embarrassment and humiliation, and loss of ability to enjoy the pleasures of life. We have filed post-trial motions, including a motion for a new trial and a request that the jury verdict be reduced. If those motions are not granted, we intend to appeal the verdict. We have accrued $5,000 which is included in Other Accrued Liabilities for this claim. Our insurer has agreed to indemnify CONSOL Energy for damages and costs in excess of our $5,000 self-retention under applicable insurance policies.

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At December 31, 2010, 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 of Commitment Expiration Per Period
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	197,972	$	124,873	$	73,099	$	—	$	—
Environmental		56,993		23,075		33,918		—		—
Gas		70,203		70,203		—		—		—
Other		11,764		11,600		164		—		—

Total Letters of Credit		336,932		229,751		107,181		—		—

Surety Bonds:
Employee-Related		199,448		199,448		—		—		—
Environmental		421,726		421,551		175		—		—
Gas		6,908		6,907		—		—		1
Other		5,599		5,576		23		—		—

Total Surety Bonds		633,681		633,482		198		—		1

Guarantees:
Coal		203,482		186,802		10,447		1,733		4,500
Gas		77,921		52,305		22,516		—		3,100
Other		371,920		69,016		109,770		74,775		118,359

Total Guarantees		653,323		308,123		142,733		76,508		125,959

Total Commitments	$	1,623,936	$	1,171,356	$	250,112	$	76,508	$	125,960

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.

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, 2010, the purchase obligations for each of the next five years and beyond were as follows:


Obligations Due	Amount
Less than 1 year	$	168,913
1 – 3 years		266,196
3 – 5 years		88,149
More than 5 years		312,085

Total Purchase Obligations	$	835,343

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Costs related to these purchase obligations include:


	For The Years Ended December 31,
	2010		2009		2008
Major equipment purchases	$	56,723	$	89,261	$	10,957
Firm transportation expense		40,274		21,668		11,476
Gas drilling obligations		28,641		—		—
Other		497		120		60

Total costs related to purchase obligations	$	126,135	$	111,049	$	22,493

Note 25—Segment Information:

CONSOL Energy has two principal business divisions: Coal and Gas. The principal activities of the Coal division are mining, preparation and marketing of steam coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal division includes four reportable segments. These reportable segments are Steam, Low Volatile Metallurgical, High Volatile Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines or type of coal sold). For the year ended December 31, 2010, the Steam aggregated segment includes the following mines: Bailey, Blacksville #2, Buchanan steam, Emery, Enlow Fork, Fola Complex, Loveridge, McElroy, Miller Creek Complex, Robinson Run and Shoemaker. For the year ended December 31, 2010, the Low Volatile Metallurgical aggregated segment includes the Buchanan mine. For the year ended December 31, 2010, the High Volatile Metallurgical aggregated segment includes: Bailey, Blacksville #2 Enlow Fork, Fola Complex and Emery coal sales. The Other Coal segment includes our purchased coal activities, idled mine activities, as well as various other activities assigned to the coal division but not allocated to each individual mine. The principal activity of the Gas division is to produce pipeline quality methane gas for sale primarily to gas wholesalers. The Gas division includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus, Conventional and Other Gas. The Other Gas segment includes our purchased gas activities as well as various other activities assigned to the gas division but not allocated to each individual well type. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities. 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 2009 and 2008 segment information have been made to conform to the 2010 presentation. Equity in earnings of affiliates was reclassified between the Coal division and the All Other segment. The Marcellus and Conventional segments are insignificant in the year ended December 31, 2008, and therefore the revenue and earnings before income taxes are reported in the Coalbed Methane segment.

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Industry segment results for the year ended December 31, 2010 are:


	Steam		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Conventional Gas			Other Gas			Total Gas			All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—Outside	$	3,001,352	$	680,212	$	172,087	$	45,738		$	3,899,389	$	569,366	$	47,700	$	116,423		$	9,067		$	742,556		$	296,758	$	—		$	4,938,703	(A)
Sales—Purchased Gas		—		—		—		—			—		—		—		—			11,227			11,227			—		—			11,227
Sales—Gas Royalty Interests		—		—		—		—			—		—		—		—			62,869			62,869			—		—			62,869
Freight—outside		—		—		—		125,715			125,715		—		—		—			—			—			—		—			125,715
Intersegment transfers		—		—		—		—			—		—		—		—			3,253			3,253			175,906		(179,159	)		—

Total Sales and Freight	$	3,001,352	$	680,212	$	172,087	$	171,453		$	4,025,104	$	569,366	$	47,700	$	116,423		$	86,416		$	819,905		$	472,664	$	(179,159	)	$	5,138,514

Earnings (Loss) Before Income Taxes	$	544,804	$	381,562	$	86,918	$	(476,790	)	$	536,494	$	248,127	$	5,112	$	(4,386	)	$	(68,975	)	$	179,878		$	22,156	$	(270,615	)	$	467,913	(B)

Segment assets										$	5,056,583											$	5,916,093		$	337,855	$	760,079		$	12,070,610	(C)

Depreciation, depletion and amortization										$	359,497											$	190,424		$	17,742	$	—		$	567,663

Capital expenditures										$	707,473											$	3,891,640	(D)	$	25,123	$	—		$	4,624,236

(A)	There were no sales to customers aggregating over 10% of total revenue in 2010.

(B)	Includes equity in earnings of unconsolidated affiliates of $13,846, $479 and $7,103 for Coal, Gas and All Other, respectively.

(C)	Includes investments in unconsolidated equity affiliates of $21,463, $23,569 and $48,477 for Coal, Gas and All Other, respectively.

(D)	Includes $3,470,212 acquisition of Dominion Exploration and Production Business.

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Industry segment results for the year ended December 31, 2009 are:


	Steam		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Conventional Gas			Other Gas			Total Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—Outside	$	3,122,223	$	248,546	$	—	$	39,117		$	3,409,886	$	595,769	$	21,006	$	7,907		$	4,247		$	628,929	$	272,976	$	—		$	4,311,791	(E)
Sales—Purchased Gas		—		—		—		—			—		—		—		—			7,040			7,040		—		—			7,040
Sales—Gas Royalty Interests		—		—		—		—			—		—		—		—			40,951			40,951		—		—			40,951
Freight—outside		—		—		—		148,907			148,907		—		—		—			—			—		—		—			148,907
Intersegment transfers		—		—		—		—			—		—		—		—			1,671			1,671		152,375		(154,046	)		—

Total Sales and Freight	$	3,122,223	$	248,546	$	—	$	188,024		$	3,558,793	$	595,769	$	21,006	$	7,907		$	53,909		$	678,591	$	425,351	$	(154,046	)	$	4,508,689

Earnings (Loss) Before Income Taxes	$	806,841	$	93,733	$	—	$	(353,845	)	$	546,729	$	303,882	$	3,940	$	(2,259	)	$	(42,115	)	$	263,448	$	15,686	$	(37,518	)	$	788,345	(F)

Segment assets										$	4,722,508											$	2,171,495	$	317,004	$	564,394		$	7,775,401	(G)

Depreciation, depletion and amortization										$	310,346											$	107,251	$	19,820	$	—		$	437,417

Capital expenditures										$	580,401											$	322,126	$	17,553	$	—		$	920,080

(E)	There were no sales to customers aggregating over 10% of total revenue in 2009.

(F)	Includes equity in earnings of unconsolidated affiliates of $5,663, $636 and $9,408 for Coal, Gas and All Other, respectively.

(G)	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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Industry segment results for the year ended December 31, 2008 are:


	Steam		Low Volatile Metallurgical		High Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Conventional Gas		Other Gas			Total Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales—Outside	$	2,725,673	$	341,177	$	—	$	117,594		$	3,184,444	$	680,990	$	—	$	—	$	—		$	680,990	$	316,135	$	—		$	4,181,569	(H)
Sales—Purchased Gas		—		—		—		—			—		—		—		—		8,464			8,464		—		—			8,464
Sales—Gas Royalty Interests		—		—		—		—			—		—		—		—		79,302			79,302		—		—			79,302
Freight—outside		—		—		—		216,968			216,968		—		—		—		—			—		—		—			216,968
Intersegment transfers		—		—		—		—			—		—		—		—		7,337			7,337		145,856		(153,193	)		—

Total Sales and Freight	$	2,725,673	$	341,177	$	—	$	334,562		$	3,401,412	$	680,990	$	—	$	—	$	95,103		$	776,093	$	461,991	$	(153,193	)	$	4,486,303

Earnings (Loss) Before Income Taxes	$	368,869	$	161,488	$	—	$	(182,590	)	$	347,767	$	400,330	$	—	$	—	$	(14,376	)	$	385,954	$	31,118	$	(39,244	)	$	725,595	(I)

Segment assets										$	4,552,584										$	2,094,748	$	322,137	$	565,989		$	7,535,458	(J)

Depreciation, depletion and amortization										$	299,831										$	70,010	$	19,780	$	—		$	389,621

Capital expenditures										$	445,594										$	560,663	$	55,412	$	—		$	1,061,669

(H)	There were no sales to customers aggregating over 10% of total revenue in 2008.

(I)	Includes equity in earnings of unconsolidated affiliates of $2,534, $551 and $8,055 for Coal, Gas and All Other, respectively.

(J)	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.

171

Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Income:


	For the Years Ended December 31,
	2010			2009			2008
Total segment sales and freight from external customers	$	5,138,514		$	4,508,689		$	4,486,303
Other income not allocated to segments (Note 3)		97,507			113,186			166,142

Total Consolidated Revenue and Other Income	$	5,236,021		$	4,621,875		$	4,652,445

Earnings Before Income Taxes:
Segment Earnings Before Income Taxes for total reportable business segments	$	716,372		$	810,177		$	733,721
Segment Earnings Before Income Taxes for all other businesses		22,156			15,686			31,118
Interest income (expense), net and other non-operating activity(K)		(208,893	)		(26,472	)		(39,244	)
Acquisition and Financing Fees(K)		(62,033	)		—			—
Fees for disposing non-core assets(K)		(2,688	)		—			—
Corporate restructuring(K)		—			(4,378	)		—
Lease Settlement(K)		2,999			(6,668	)		—

Earnings Before Income Taxes	$	467,913		$	788,345		$	725,595


	December 31,
	2010			2009			2008
Total Assets:
Segment assets for total reportable business segments	$	10,972,676		$	6,894,003		$	6,647,332
Segment assets for all other businesses		337,855			317,004			322,137
Items excluded from segment assets:
Cash and other investments(K)		16,836			65,025			136,951
Recoverable income taxes		32,528			—			33,862
Deferred tax assets		659,017			498,680			394,142
Bond issuance costs		51,698			689			1,034

Total Consolidated Assets	$	12,070,610		$	7,775,401		$	7,535,458

(K)	Excludes amounts specifically related to the gas segment.

Enterprise-Wide Disclosures:

CONSOL Energy’s Revenues by geographical location:


	For the Years Ended December 31,
	2010		2009		2008
United States	$	4,684,358	$	4,026,619	$	3,841,665
Europe		208,762		298,262		462,291
South America		233,466		120,174		94,230
Canada		3,251		25,056		88,106
Other		8,677		38,578		11

Total Revenues and Freight from External Customers(L)	$	5,138,514	$	4,508,689	$	4,486,303

(L)	CONSOL Energy attributes revenue to individual countries based on the location of the customer.

172

CONSOL Energy’s Property, Plant and Equipment by geographical location are:


	December 31,
	2010		2009		2008
United States	$	10,095,851	$	6,090,703	$	5,732,021
Canada		33,400		33,587		33,828
Belgium		—		—		123

	$	10,129,251	$	6,124,290	$	5,765,972

Note 26—Guarantor Subsidiaries Financial Information:

The payment obligations under the $250,000, 7.875% per annum notes due March 1, 2012, the $1,500,000, 8.000% per annum notes due April 1, 2017, and the $1,250,000, 8.250% per annum notes due April 1, 2020 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by substantially all of the 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, a guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. 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.

Income Statement for the Year Ended December 31, 2010:


	Parent Issuer			CNX Gas Guarantor		Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	745,809	$	4,002,790		$	196,118	$	(6,014	)	$	4,938,703
Sales—Purchased Gas		—			11,227		—			—		—			11,227
Sales—Gas Royalty Interests		—			62,869		—			—		—			62,869
Freight—Outside		—			—		125,715			—		—			125,715
Other Income (including equity earnings)		565,780			5,174		51,004			29,851		(554,302	)		97,507

Total Revenue and Other Income		565,780			825,079		4,179,509			225,969		(560,316	)		5,236,021
Cost of Goods Sold and Other Operating
Charges		102,645			258,278		2,636,360			10,858		254,186			3,262,327
Purchased Gas Costs		—			9,736		—			—		—			9,736
Acquisition and Financing Fees		62,031			3,330		2			—		—			65,363
Gas Royalty Interests’ Costs		—			53,839		—			—		(64	)		53,775
Related Party Activity		(11,676	)		—		(10,059	)		180,398		(158,663	)		—
Freight Expense		—			—		125,544			—		—			125,544
Selling, General and Administrative
Expense		—			92,886		134,590			1,068		(78,334	)		150,210
Depreciation, Depletion and Amortization		10,641			190,424		363,961			2,637		—			567,663
Interest Expense		188,343			7,196		9,838			25		(370	)		205,032
Taxes Other Than Income		6,599			29,882		289,160			2,817		—			328,458

Total Costs		358,583			645,571		3,549,396			197,803		16,755			4,768,108

Earnings (Loss) Before Income Taxes		207,197			179,508		630,113			28,166		(577,071	)		467,913
Income Tax Expense (Benefit)		(139,584	)		73,378		164,838			10,655		—			109,287

Net Income (Loss)		346,781			106,130		465,275			17,511		(577,071	)		358,626
Less: Net Income Attributable to Noncontrolling Interest		—			—		—			—		(11,845	)		(11,845	)

Net Income (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	346,781		$	106,130	$	465,275		$	17,511	$	(588,916	)	$	346,781

173

Balance Sheet for December 31, 2010:


	Parent Issuer			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	11,382		$	16,559		$	3,235		$	1,618	$	—		$	32,794
Accounts and Notes Receivable:
Trade		—			65,197			646			186,687		—			252,530
Securitized		200,000			—			—			—		—			200,000
Other		4,635			3,361			10,915			2,678		—			21,589
Inventories		—			4,456			203,962			50,120		—			258,538
Recoverable Income Taxes		(3,189	)		35,717			—			—		—			32,528
Deferred Income Taxes		173,211			960			—			—		—			174,171
Prepaid Expenses		35,297			57,907			39,309			10,343		—			142,856

Total Current Assets		421,336			184,157			258,067			251,446		—			1,115,006
Property, Plant and Equipment:
Property, Plant and Equipment		166,884			6,336,121			8,422,235			26,118		—			14,951,358
Less-Accumulated Depreciation, Depletion and Amortization		91,952			628,506			4,083,693			17,956		—			4,822,107

Property, Plant and Equipment-Net		74,932			5,707,615			4,338,542			8,162		—			10,129,251
Other Assets:
Deferred Income Taxes		902,188			(417,342	)		—			—		—			484,846
Investment in Affiliates		7,848,069			23,569			952,138			11,087		(8,741,354	)		93,509
Restricted Cash		20,291			—			—			—		—			20,291
Other		118,149			37,268			61,532			10,758		—			227,707

Total Other Assets		8,888,697			(356,505	)		1,013,670			21,845		(8,741,354	)		826,353

Total Assets	$	9,384,965		$	5,535,267		$	5,610,279		$	281,453	$	(8,741,354	)	$	12,070,610

Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	130,063		$	101,944		$	113,036		$	8,968	$	—		$	354,011
Accounts Payable (Recoverable)- Related Parties		2,363,108			30,302			(2,543,991	)		150,581		—			—
Short-Term Notes Payable		155,000			129,000			—			—		—			284,000
Current Portion Long-Term Debt		758			9,851			13,589			585		—			24,783
Borrowings under Securitization Facility		200,000			—			—			—		—			200,000
Other Accrued Liabilities		302,788			59,960			425,735			13,508		—			801,991

Total Current Liabilities		3,151,717			331,057			(1,991,631	)		173,642		—			1,664,785
Long-Term Debt:		3,000,702			58,905			125,627			904		—			3,186,138
Deferred Credits and Other Liabilities
Postretirement Benefits Other Than Pensions		—			—			3,077,390			—		—			3,077,390
Pneumoconiosis		—			—			173,616			—		—			173,616
Mine Closing		—			—			393,754			—		—			393,754
Gas Well Closing		—			60,027			70,951			—		—			130,978
Workers’ Compensation		—			—			148,265			49		—			148,314
Salary Retirement		161,173			—			—			—		—			161,173
Reclamation		—			—			53,839			—		—			53,839
Other		112,775			25,483			6,352			—		—			144,610

Total Deferred Credits and Other Liabilities		273,948			85,510			3,924,167			49		—			4,283,674
Total CONSOL Energy Inc. Stockholders’ Equity		2,958,598			5,068,259			3,543,652			106,858		(8,732,890	)		2,944,477
Noncontrolling Interest		—			(8,464	)		8,464			—		(8,464	)		(8,464	)

Total Liabilities and Stockholders’ Equity	$	9,384,965		$	5,535,267		$	5,610,279		$	281,453	$	(8,741,354	)	$	12,070,610

174

Condensed Statement of Cash Flows

For the Year Ended December 31, 2010:


	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non- Guarantors			Elimination			Consolidated
Net Cash Provided by Operating Activities	$	93,623		$	361,073		$	675,627		$	989		$	—		$	1,131,312

Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(421,428	)	$	(732,596	)	$	—		$	—		$	(1,154,024	)
Acquisition of Dominion Exploration and Production Business		—			—			(3,470,212	)		—			—			(3,470,212	)
Purchase of CNX Gas Noncontrolling Interest		(991,034	)		—			—			—			—			(991,034	)
Investment in Equity Affiliates		(3,470,212	)		1,501			9,951			—			3,470,212			11,452
Other Investing Activities		—			562			59,282			—			—			59,844

Net Cash (Used in) Provided by Investing Activities	$	(4,461,246	)	$	(419,365	)	$	(4,133,575	)	$	—		$	3,470,212		$	(5,543,974	)

Cash Flows from Financial Activities:
Dividends Paid	$	(85,861	)	$	—		$	—		$	—		$	—		$	(85,861	)
(Payments on) Proceeds from Short Term Borrowing		(260,000	)		71,150			—			—			—			(188,850	)
Proceeds from Securitization Facility		150,000			—			—			—			—			150,000
Proceeds from Long Term Notes		2,750,000			—			—			—			—			2,750,000
Proceeds from Issuance of Common Stock		1,828,862			—			—			—			—			1,828,862
Proceeds from Parent		—			—			3,470,212			—			(3,470,212	)		—
Debt Issuance and Financing Fees		(84,248	)		—			—			—			—			(84,248	)
Other Financing Activities		20,703			2,577			(12,793	)		(541	)		—			9,946

Net Cash Provided by (Used in) Financing Activities	$	4,319,456		$	73,727		$	3,457,419		$	(541	)	$	(3,470,212	)	$	4,379,849

175

Income Statement for the Year Ended December 31, 2009:


	Parent Issuer			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 Interests		—			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			188,454		2,050,591			190,854		242,193			2,757,052
Purchased Gas Costs		—			6,442		—			—		—			6,442
Gas Royalty Interests’ Costs		—			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		—			66,655		151,158			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 Taxes		—			—		(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 Tax Expense (Benefit)		(45,340	)		98,636		160,105			7,802		—			221,203

Net Income (Loss)		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 (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	539,717		$	164,462	$	476,704		$	12,821	$	(653,987	)	$	539,717

176

Balance Sheet for December 31, 2009:


	Parent Issuer		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
Securitized		50,000		—			—			—					50,000
Other		5,274		975			7,063			2,671		—			15,983
Inventories		—		—			262,755			44,842		—			307,597
Deferred Income Taxes		108,254		(34,871	)		—			—		—			73,383
Prepaid Expenses		13,537		103,094			42,209			2,166		—			161,006

Total Current Assets		236,614		113,743			315,904			324,775		—			991,036
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		67,349		21,627			50,603			11,666		—			151,245

Total Other Assets		5,226,962		(288,275	)		847,872			15,587		(5,142,071	)		660,075

Total Assets	$	5,542,988	$	1,802,018		$	5,223,640		$	348,826	$	(5,142,071	)	$	7,775,401

Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	93,876	$	53,516		$	114,872		$	7,296	$	—		$	269,560
Accounts Payable (Recoverable)
Related Parties		2,095,280		5,171			(2,351,508	)		251,057		—			—
Short-Term Notes Payable		415,000		57,850			—			—		—			472,850
Current Portion Long-Term Debt		501		8,616			35,853			424		—			45,394
Accrued Income Taxes		27,944		31,765			(31,765	)		—		—			27,944
Borrowings under Securitization Facility . .		50,000		—			—			—		—			50,000
Other Accrued Liabilities		546,066		25,455			34,569			6,748		—			612,838

Total Current Liabilities		3,228,667		182,373			(2,197,979	)		265,525		—			1,478,586
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
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
Total 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	$	5,542,988	$	1,802,018		$	5,223,640		$	348,826	$	(5,142,071	)	$	7,775,401

177

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	$	179,095		$	360,163		$	523,596		$	(2,403	)	$	—	$	1,060,451

Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(336,447	)	$	(583,633	)	$	—		$	—	$	(920,080	)
Investment in Equity
Affiliates		—			1,250			3,605			—			—		4,855
Other Investing Activities		—			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 (Payments on) Short Term Borrowing		(70,000	)		(14,850	)		—			—			—		(84,850	)
Payments on Securitization Facility		(115,000	)		—			—			—			—		(115,000	)
Other Financing Activities		5,275			(11,206	)		(9,481	)		(461	)		—		(15,873	)

Net Cash (Used in) Provided by Financing Activities	$	(252,017	)	$	(26,056	)	$	(9,481	)	$	(461	)	$	—	$	(288,015	)

178

Income Statement for the Year Ended December 31, 2008:


	Parent Issuer			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 Interests		—			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 Interests’ Costs		—			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 Taxes		—			—		(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 Tax Expense (Benefit)		(40,129	)		153,656		120,315			6,092		—			239,934

Net Income (Loss)		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 (Loss) Attributable to CONSOL Energy Inc. Shareholders	$	442,470		$	239,073	$	331,323		$	10,011	$	(580,407	)	$	442,470

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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	$	(4,953	)	$	447,375		$	510,475		$	36,967		$	—	$	989,864

Cash Flows from Investing Activities:
Capital Expenditures	$	(11,371	)	$	(560,663	)	$	(464,603	)	$	(25,032	)	$	—	$	(1,061,669	)
Investment in Equity
Affiliates		—			1,081			798			—			—		1,879
Other Investing Activities		—			450			(39,516	)		—			—		(39,066	)

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 (Payments on)		237,500			72,700											310,200
Short Term Borrowing		(97,794	)		—			—			—			—		(97,794	)
Proceeds from Securitization Facility		39,600			—			—			—			—		39,600
Other Financing Activities		37,218			8,935			(8,364	)		(10,985	)		—		26,804

Net Cash Provided by (Used in) Financing Activities	$	143,567		$	81,635		$	(8,364	)	$	(10,985	)	$	—	$	205,853

Supplemental Coal Data (unaudited):


	Millions of Tons For the Year Ended December 31,
	2010			2009			2008			2007			2006
Proved and probable reserves at beginning of period		4,520			4,543			4,526			4,272			4,546
Purchased reserves		4			5			—			177			3
Reserves sold in place		(41	)		(3	)		(12	)		(33	)		(2	)
Production		(63	)		(59	)		(65	)		(65	)		(67	)
Revisions and other changes		(19	)		34			94			175			(208	)

Consolidated proved and probable reserves at end of period*		4,401			4,520			4,543			4,526			4,272

Proportionate share of proved and probable reserves of unconsolidated equity affiliates*		172			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.

CONSOL Energy’s coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2010, 629 million tons were assigned to mines either in production, temporarily idle, or under development. The proved and probable reserves at December 31, 2010 include 3,839 million tons of steam coal

180

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 13 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. The reserves also include 562 million tons of metallurgical coal in consolidated reserves, of which approximately 65 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu, and an additional 35 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,
	2010			2009
Proven properties	$	1,615,540		$	152,010
Unproven properties		2,206,827			271,553
Wells and related equipment		1,558,300			1,171,146
Gathering assets		941,772			804,212

Total Property, Plant and Equipment		6,322,439			2,398,921
Accumulated Depreciation, Depletion and Amortization		(623,575	)		(429,966	)

Net Capitalized Costs	$	5,698,864		$	1,968,955

Costs incurred for property acquisition, exploration and development (*):


	For the Years Ended December 31,
	2010		2009		2008
Property acquisitions
Proved properties	$	1,476,470	$	30,405	$	17,090
Unproved properties		1,922,334		50,705		119,168
Development		472,691		181,944		378,119
Exploration		58,655		46,023		68,495

Total	$	3,930,150	$	309,077	$	582,872

(*)	Includes costs incurred whether capitalized or expensed.

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Results of Operations for Producing Activities:


	For the Years Ended December 31,
	2010		2009		2008
Production Revenue	$	745,809	$	630,598	$	688,325
Royalty Interest Gas Revenue		62,869		40,951		79,302
Purchased Gas Revenue		11,227		7,040		8,464

Total Revenue		819,905		678,589		776,091

Lifting Costs		87,155		55,285		67,653
Gathering Costs		127,927		95,687		83,752
Royalty Interest Gas Costs		53,839		32,423		74,041
Other Costs		63,941		45,795		34,078
Purchased Gas Costs		9,736		6,442		8,175
DD&A		190,424		107,251		70,010

Total Costs		533,022		342,883		337,709

Pre-tax Operating Income		286,883		335,706		438,382
Income Taxes		117,278		125,890		171,407

Results of Operations for Producing Activities excluding Corporate and Interest Costs	$	169,605	$	209,816	$	266,975

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,
	2010		2009		2008
Production in million cubic feet		127,875		94,415		76,562
Average gas sales price before effects of financial settlements (per thousand cubic feet)	$	4.53	$	4.15	$	8.99
Average effects of financial settlements (per thousand cubic feet)	$	1.30	$	2.53	$	—
Average gas sales price including effects of financial settlements (per thousand cubic feet)	$	5.83	$	6.68	$	8.99
Average lifting costs, excluding ad valorem and severance taxes (per thousand cubic feet)	$	0.50	$	0.48	$	0.58

During the years ended December 31, 2010, 2009 and 2008, we drilled 317, 247 and 534 net development wells, respectively. There was one dry development well in 2010 and one dry development well in 2009. There were no dry development wells in 2008.

During the years ended December 31, 2010, 2009 and 2008, we drilled 38, 18 and 56 net exploratory wells, respectively. Of the wells drilled in the years ended December 31, 2010, 2009 and 2008, there were two, one and three dry wells, respectively.

At December 31, 2010, there were twenty-one 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 2011.

At December 31, 2010, there were no exploratory wells in the process of being drilled.

CONSOL Energy is committed to provide 82.8 bcf of gas under existing sales contracts or agreements over the course of the next four years. CONSOL Energy expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.

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	Gross		Net(1)
Producing Wells (including gob wells)		14,747		12,587

Proved Developed Acreage		514,948		490,469
Proved Undeveloped Acreage		146,173		139,944
Unproved Acreage		9,134,672		6,251,754

Total Acreage		9,795,793		6,882,167

(1)

Proved Oil and Gas Reserve Quantities:

The preparation of our gas reserve estimates are completed in accordance with CONSOL Energy’s 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 2010 gas reserve results were audited by Netherland Sewell. The technical person primarily responsible for overseeing the audit of our reserves is a registered professional engineer. The gas reserve estimates are as follows:


	2010			2009			2008
	Consolidated Operations			Consolidated Operations			Consolidated Operations			Equity Affiliates
Net Reserve Quantity (MMcfe)
Beginning reserves		1,911,391			1,422,046			1,339,909			3,584
Revisions(b)		379,977			177,004			(30,828	)		—
Extensions and discoveries(c)		621,270			406,756			182,701			—
Production		(127,875	)		(94,415	)		(76,562	)		—
Acquisition of remaining interest in equity affiliate		—			—			3,584			(3,584	)
Purchases of reserves in-place		946,834			—			3,242			—

Ending reserves(a)		3,731,597			1,911,391			1,422,046			—

(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. CONSOL Energy 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 CBM 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 price, 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 drilling of proved undeveloped, probable and possible locations, approvals from the Oil & Gas Board in Virginia to drill and complete wells on tighter spacing and changes

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in SEC guidelines on booking Proven Undeveloped (PUD) locations more than one location away if reliable technology can be demonstrated. The reliable technologies that were utilized include wire line open hole log data, performance data, log cross sections, core data and statistical analysis. The statistical method utilized production performance from CONSOL Energy’s and competitors’ wells. Geophysical data include data from CONSOL Energy’s wells, published documents and state data-sites and were used to confirm continuity of the formation.


	2010						2009						2008
	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		1,040,257		1,039,052		1,205		783,290		783,010		280		667,726		667,443		283

End of year		1,931,272		1,924,036		7,236		1,040,257		1,039,052		1,205		783,290		783,010		280

Proved undeveloped reserves consolidated entities only)
Beginning of year		871,134		871,134		—		638,756		638,756		—		672,183		672,183		—

End of year		1,800,325		1,800,325		—		871,134		871,134		—		638,756		638,756		—


	For the Year Ended December 31, 2010
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves		871,134
Undeveloped reserves transferred to developed(a)		(89,084	)
Acquisition of reserves in place		323,665
Revisions		134,663
Extension and discoveries		559,947

Ending proved undeveloped reserves(b)		1,800,325

(a)	During 2009, various exploration and development drilling and evaluations were completed. Approximately, $86,048 of capital was spent in the year ended December 31, 2010 related to undeveloped reserves that were transferred to developed.

(b)

Included in proved undeveloped reserves at December 31, 2010 are approximately 136,066 MMcfe of reserves that have been reported for more than five years. These reserves specifically relate to CONSOL Energy’s Buchanan Mine, more specifically, to GOB (a rubble zone formed in the cavity created by the extraction of coal) production due to a complex fracture being generated in the overburden strata above the mined seam. Mining operations take a significant amount of time and our GOB forecasts are consistent with the future plans of the Buchanan Mine. Evidence also exists that supports the continual operation of the mine for many years past, unless there was an extreme circumstance which resulted from an external factor. These reasons constitute that specific circumstances exist to continue recognizing these reserves for CONSOL Energy.

The following table represents the capitalized exploratory well cost activity as indicated:


	December 31, 2010
Costs pending the determination of proved reserves at December 31, 2010(a)
Less than one year	$	4,671
More than one year but less than five years		3,807
More than five years		1,680

Total	$	10,158

(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. During 2010, nine wells were removed from the previous year-end schedule. Eight of these wells were connected and are now producing while one well was determined to be dry or uneconomical to pursue and expensed.

184


	For the Years Ended December 31,
	2010		2009		2008
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves	$	93,482	$	52,332	$	1,887
Costs expensed due to determination of dry hole or abandonment of project	$	9,614	$	8,194	$	1,197

CONSOL Energy’s 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, 2010. 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 CONSOL Energy. 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. CONSOL Energy’s 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 CONSOL Energy’s 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,
	2010			2009			2008
Future Cash Flows:
Revenues	$	16,723,795		$	7,975,195		$	8,856,817
Production costs		(5,175,563	)		(3,123,532	)		(3,525,902	)
Development costs		(2,720,243	)		(995,569	)		(793,592	)
Income tax expense		(3,354,444	)		(1,465,075	)		(1,713,713	)

Future Net Cash Flows		5,473,545			2,391,019			2,823,610
Discounted to present value at a 10% annual rate		(3,812,724	)		(1,496,668	)		(1,605,176	)

Total standardized measure of discounted net cash flows	$	1,660,821		$	894,351		$	1,218,434

185

The following are the principal sources of change in the standardized measure of discounted future net cash flows during:


	December 31,
	2010			2009			2008
	Consolidated Operations			Consolidated Operations			Consolidated Operations			Equity Affiliates
Balance at beginning of period	$	894,351		$	1,218,434		$	1,384,983		$	4,557
Net changes in sales prices and production costs		721,997			(457,138	)		(872,702	)		—
Sales net of production costs		(286,883	)		(335,706	)		(438,382	)		—
Net change due to revisions in quantity estimates		414,704			189,583			(63,547	)		—
Net change due to extensions, discoveries, and improved recovery		326,584			124,008			196,344			—
Net change due to acquisition		500,376			—			4,158			—
Acquisition of remaining interest in equity affiliate		—			—			4,557			(4,557	)
Development costs incurred during the period		295,142			181,944			378,119			—
Difference in previously estimated development costs compared to actual costs incurred during the period		(12,060	)		(3,282	)		(136,742	)		—
Changes in estimated future development costs		(426,870	)		(380,639	)		(398,534	)		—
Net change in future income taxes		(612,114	)		248,639			545,702			—
Accretion of discount and other		(154,406	)		108,508			614,478			—

Total discounted cash flow at end of period	$	1,660,821		$	894,351		$	1,218,434		$	—

Supplemental Quarterly Information (unaudited):

(Dollars in thousands)


	Three Months Ended
	March 31, 2010		June 30, 2010		September 30, 2010		December 31, 2010
Sales	$	1,186,869	$	1,236,007	$	1,282,154	$	1,307,769
Freight Revenue	$	31,200	$	28,075	$	37,269	$	29,171
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests’ Costs and Purchased Gas Costs.	$	781,367	$	831,638	$	870,560	$	842,273
Freight Expense	$	31,200	$	28,075	$	37,269	$	29,000
Net Income	$	107,882	$	70,900	$	75,383	$	104,461
Net Income Attributable to CONSOL Energy Inc Shareholders	$	100,269	$	66,668	$	75,383	$	104,461
Total Earnings per Share
Basic	$	0.55	$	0.30	$	0.33	$	0.46

Diluted .	$	0.54	$	0.29	$	0.33	$	0.46

Weighted Average Shares Outstanding
Basic		181,726,480		225,715,539		225,781,539		225,854,413

Diluted .		184,348,982		228,081,103		228,092,299		228,169,569

186


	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

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Item 9.

Changes in and 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.

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, 2010. 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, 2010.

The effectiveness of CONSOL Energy’s internal control over financial reporting as of December 31, 2010 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.

As previously discussed in Note 2—Acquisitions and Dispositions of this Form 10-K, CONSOL Energy

188

completed the acquisition of the Appalachian oil and gas exploration and production business of Dominion Resources, Inc. for $3,470,212 on April 30, 2010. The acquired business accounts for $3,542,984 of total assets as of December 31, 2010 and $133,850 of revenues for the year ended December 31, 2010. Although aspects of the business were incorporated into the existing control structure and tested accordingly, management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2010 excludes a comprehensive review of the aforementioned business.

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.

189

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of CONSOL Energy Inc. and Subsidiaries

We have audited CONSOL Energy Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2010, 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. and Subsidiaries’ 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. and Subsidiaries’ maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.

As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the acquired Appalachian oil and gas exploration and production business acquired from Dominion Resources, Inc., which is included in the 2010 consolidated financial statements of CONSOL Energy, Inc. and Subsidiaries and constituted $3.5 billion of total assets and $134 million of revenues for the year then ended December 31, 2010. Our audit of internal control over financial reporting of CONSOL Energy, Inc. and Subsidiaries also did not include an evaluation of the internal control over financial reporting of the acquired Appalachian oil and gas exploration and production business acquired from Dominion Resources, Inc.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of CONSOL Energy Inc. and Subsidiaries’ as of December 31, 2010 and 2009, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010 of CONSOL Energy Inc. and Subsidiaries’ and our report dated February 10, 2011 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

February 10, 2011

190

Item 9B.

Other Information.

Mine Safety and Health Administration Safety Data

We believe that CONSOL Energy is one of the safest mining companies in the world. The Company has in place health and safety programs that include extensive employee training, accident prevention, workplace inspection, emergency response, accident investigation, regulatory compliance and program auditing. The objectives of our health and safety programs are to eliminate workplace incidents, comply with all mining-related regulations and provide support for both regulators and the industry to improve mine safety.

The operation of our mines is subject to regulation by the federal Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). MSHA inspects our mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. We present information below regarding certain mining safety and health citations which MSHA has issued with respect to our coal mining operations. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size of the coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed.

During the three months ended December 31, 2010, CONSOL Energy’s mining complexes were assessed one Mine Act section 110(b)(2) penalty for failure to correct the subject matter of a Mine Act section 104(a) citation within the specified time period, which failure was deemed flagrant (i.e., a reckless or repeated failure to make reasonable efforts to eliminate a known violation that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury). Neither CONSOL Energy’s mining complexes nor its closed and/or idled mines: (i) received any Mine Act section 107(a) imminent danger orders to immediately remove miners; or (ii) received any MSHA written notices under Mine Act section 104(e) of a pattern of violation of mandatory health or safety standards or the potential to have such a pattern. There was one pending legal action before the Federal Mine Safety and Health Review Commission. There were no fatalities during the three months ended December 31, 2010.

During the year ended December 31, 2010, CONSOL Energy’s mining complexes including its closed and/or idled mines were assessed nine Mine Act section 110(b)(2) penalties for failure to correct the subject matter of a Mine Act section 104(a) citation within the specified time period, which failure was deemed flagrant (i.e., a reckless or repeated failure to make reasonable efforts to eliminate a known violation that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury) and one Mine Act section 107(a) imminent danger order to immediately remove miners. Neither CONSOL Energy’s mining complexes nor its closed and/or idled mines received any MSHA written notices under Mine Act section 104(e) of a pattern of violation of mandatory health or safety standards or the potential to have such a pattern. There was one pending legal action before the Federal Mine Safety and Health Review Commission. In addition, there was one fatality at the Loveridge Mine during the year ended December 31, 2010.

The table below sets forth by mining complex the total number of citations and/or orders issued during the indicated periods by MSHA to CONSOL Energy and its subsidiaries under the indicated provisions of the Mine Act, together with the total dollar value of proposed MSHA assessments, received during the three months and year ended December 31, 2010.

191

For the three months ended December 31, 2010:


Name of Mine or Mining Complex(1)(2)	Mine Act Section 104 Significant & Substantial Citations(3)		Mine Act Section 104(b) Orders(4)		Mine Act Section 104(d) Citations & Orders(5)		Total Dollar Value of Proposed MSHA Assessments(6) (in thousands)		Number of Legal Actions Pending before the Federal Mine Safety and Health Review Commission(7)
Enlow Fork		19		—		—	$	20		18
Bailey		11		—		—	$	38		17
McElroy		37		—		—	$	968		24
Shoemaker		88		1		5	$	54		9
Loveridge		58		—		2	$	345		7
Robinson Run		29		—		1	$	372		21
Blacksville #2		41		—		2	$	508		14
Buchanan		52		—		—	$	270		19
AMVEST—Fola Complex		7		—		2	$	10		8
Miller Creek Complex		17		—		—	$	28		10
Emery		7		—		—	$	61		14
Other (Keystone Plant)		—		—		—	$	1		—

(1)

MSHA assigns an identification number to each coal mine and may or may not assign separate identification numbers to related facilities such as preparation plants. We are providing the information in the table by mining complex rather than MSHA identification number because that is how we manage and operate our coal mining business.

(2)

We have not included currently closed or idled mines in the above table, except with respect to the Emery Mine, which was idled on December 17, 2010. Our closed and/or idled mines did not receive any of the indicated citations in the three months ended December 31, 2010, except with respect to Emery Mine. There were 4 legal actions in total pending before the Federal Mine Safety and Health Review Commission for our closed and/or idle mines. These actions may have been initiated in prior quarters.

(3)	Mine Act section 104(a) significant and substantial citations are for alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to will result in an injury or illness of a reasonably serious nature.

(4)	Mine Act section 104(b) orders are for alleged failure to totally abate the subject matter of a Mine Act section 104(a) citation within the period specified in the citation.

(5)	Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.

(6)	Includes proposed MSHA assessments received during the three months ended December 31, 2010 for all alleged violations. MSHA assessments are not necessarily made in the same period as the citation occurs.

(7)

Includes all legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for each of our mining complexes. These actions may have been initiated in prior quarters. All of the legal actions were initiated by us to contest citations, orders, or proposed assessments issued by MSHA, and if we are successful, may result in the reduction or dismissal of those citations, orders or assessments.

192

For the year ended December 31, 2010


Name of Mine or Mining Complex(1)(2)	Mine Act Section 104 Significant & Substantial Citations(3)		Mine Act Section 104(b) Orders(4)		Mine Act Section 104(d) Citations & Orders(5)		Total Dollar Value of Proposed MSHA Assessments(6) (in thousands)		Number of Legal Actions Pending before the Federal Mine Safety and Health Review Commission(7)
Enlow Fork		73		—		—	$	523		18
Bailey		127		—		—	$	305		17
McElroy		353		—		8	$	2,417		24
Shoemaker		268		4		10	$	208		9
Loveridge		251		2		9	$	1,544		7
Robinson Run		232		—		6	$	833		21
Blacksville #2		207		1		9	$	783		14
Buchanan		303		1		7	$	1,319		19
AMVEST—Fola Complex		36		—		2	$	75		8
Miller Creek Complex		68		—		—	$	101		10
Emery		49		—		—	$	341		14
Other (Keystone Plant)		4		—		—	$	5		—

(1)

(2)

We have not included currently closed or idled mines in the above table, except with respect to the Emery Mine, which was idled on December 17, 2010. Our closed and/or idled mines did not receive any of the indicated citations in the year ended December 31, 2010, except with respect to Emery Mine. There were 4 legal actions in total pending before the Federal Mine Safety and Health Review Commission for our closed and/or idle mines. These actions may have been initiated in prior years.

(3)	Mine Act section 104(a) significant and substantial citations are for alleged violations of a mining safety standard or regulation where there exists a reasonable likelihood that the hazard contributed to will result in an injury or illness of a reasonably serious nature.

(4)	Mine Act section 104(b) orders are for alleged failure to totally abate the subject matter of a Mine Act section 104(a) citation within the period specified in the citation.

(5)	Mine Act section 104(d) citations and orders are for an alleged unwarrantable failure (i.e. aggravated conduct constituting more than ordinary negligence) to comply with a mining safety standard or regulation.

(6)	Includes proposed MSHA assessments received during the year ended December 31, 2010 for all alleged violations. MSHA assessments are not necessarily made in the same period as the citation occurs.

(7)

Includes all legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for each of our mining complexes. These actions may have been initiated in prior years. All of the legal actions were initiated by us to contest citations, orders, or proposed assessments issued by MSHA, and if we are successful, may result in the reduction or dismissal of those citations, orders or assessments.

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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—Biographies of Directors,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION—BOARD OF DIRECTORS AND ITS COMMITTEES—Corporate Governance Web Page and 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, 2011 (the “Proxy Statement”).

Executive Officers of CONSOL Energy

The following is a list of CONSOL Energy executive officers, their ages as of February 15, 2011 and their positions and offices held with CONSOL Energy.


Name	Age		Position
J. Brett Harvey		60	Chairman of the Board, President and Chief Executive Officer
Nicholas J. DeIuliis		42	Executive Vice President and Chief Operating Officer
William J. Lyons		62	Executive Vice President and Chief Financial Officer
P. Jerome Richey		61	Secretary and Executive Vice President Corporate Affairs and Chief Legal Officer
Robert P. King		58	Executive Vice President Business Advancements and Support Services
Robert F. Pusateri		60	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 was elected Chairman of the Board of CONSOL Energy on June 29, 2010. 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 has been Executive Vice President and Chief Operating Officer of CONSOL Energy since January 16, 2009. He 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, a position which he continues to hold.

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 Vice President, General Counsel and

194

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.

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, our principal financial and accounting officer 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 June 2, 2010, 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—2010,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION—UNDERSTANDING OUR DIRECTOR COMPENSATION TABLE” “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.

195

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” in the Proxy Statement.

Item 15.

Exhibit Index

In reviewing any agreements incorporated by reference in this Form 10-K or filed with this 10-K, please remember that such agreements are included to provide information regarding their terms. They are not intended to be a source of financial, business or operational information about CONSOL Energy or any of its subsidiaries or affiliates. The representations, warranties and covenants contained in these agreements are made solely for purposes of the agreements and are made as of specific dates; are solely for the benefit of the parties; may be subject to qualifications and limitations agreed upon by the parties in connection with negotiating the terms of the agreements, including being made for the purpose of allocating contractual risk between the parties instead of establishing matters as facts; and may be subject to standards of materiality applicable to the contracting parties that differ from those applicable to investors or security holders. Investors and security holders should not rely on the representations, warranties and covenants or any description thereof as characterizations of the actual state of facts or condition of CONSOL Energy or any of its subsidiaries or affiliates or, in connection with acquisition agreements, of the assets to be acquired. Moreover, information concerning the subject matter of the representations, warranties and covenants may change after the date of the agreements. Accordingly, these representations and warranties alone may not describe the actual state of affairs as of the date they were made or at any other time.


(A)(1)		Financial Statements Contained in Item 8 hereof.

(A)(2)		Financial Statement Schedule—Schedule II Valuation and qualifying accounts.

2.1		Purchase and Sale Agreement, dated as of March 14, 2010, among Dominion Resources, Inc., Dominion Transmission, Inc., Dominion Energy, Inc. and CONSOL Energy Holdings LLC VI, incorporated by reference to Exhibit 2.1 to Form 8-K (file no. 001-14901) filed on March 16, 2010.

2.2		Parent Guarantee, dated March 14, 2010, by and among CONSOL Energy Inc. and Dominion Resources, Inc., Dominion Transmission, Inc. and Dominion Energy, Inc., incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 16, 2010.

3.1		Restated Certificate of Incorporation of CONSOL Energy Inc., incorporated by reference to Exhibit 3.1 to Form 8-K (file no. 001-14901) filed on May 8, 2006.

3.2		Amended and Restated Bylaws of CONSOL Energy Inc., dated as of September 21, 2010, incorporated by reference to Exhibit 3.2 to Form 8-K (file no. 001-14901) filed on September 22, 2010.

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, with respect to the 7.875% Notes due 2012, 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.

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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.2 to Form 10-K (file no. 001-14901) for the transition period of July 31, 2001 to December 31, 2001 (file no. 001-14901), filed on March 29, 2002.

4.3		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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.2 to Form 10-Q (file no. 001-14901) for the quarter ended November 30, 2003, filed on November 19, 2003.

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4.4		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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.4 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2005, filed on August 3, 2005.

4.5		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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 10.78 to Form 8-K (file no. 001-14901) filed on August 12, 2005.

4.6		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, with respect to the 7.875% Notes due 2012, 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.

4.7		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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.8 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2006, filed on November 2, 2006.

4.8		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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.9 to Form 10-Q (file no. 001-14901) for the quarter ended September 31, 2007, filed on April 30, 2007.

4.9		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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.10 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2007, filed on August 1, 2007.

4.10		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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 11 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2007, filed on November 1, 2007.

4.11		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, with respect to the 7.875% Notes due 2012, 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.

4.12		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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.13 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2008, filed on August 5, 2008.

4.13		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, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.14 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2008, filed on August 5, 2008.

4.14		Supplemental Indenture No. 13, dated as of March 22, 2010, by and among CONSOL Energy Inc. and certain Guarantors listed on Schedule I thereto and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.4 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2010, filed on August 2, 2010.

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4.15		Supplemental Indenture No. 14, dated as of April 30, 2010, by and among CONSOL Energy Inc., certain Guarantors listed on Schedule I thereto and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 7.875% Notes due 2012, incorporated by reference to Exhibit 4.5 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2010, filed on August 2, 2010.

4.16		Indenture, dated as of April 1, 2010, among CONSOL Energy Inc., the Subsidiary Guarantors named therein and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Notes due 2017, incorporated by reference to Exhibit 4.1 to Form 8-K (file no. 001-14901) filed on April 2, 2010.

4.17		Supplemental Indenture, dated as of April 30, 2010, among Dominion Exploration & Production, Inc., Dominion Reserves, Inc., Dominion Coalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian Development Properties, LLC, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.4 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.

4.18		Supplemental Indenture No. 2, dated as of June 16, 2010, among Cardinal States Gathering Company, CNX Gas Company LLC, CNX Gas Corporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.00% Senior Notes due 2017, incorporated by reference to Exhibit 4.5 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.

4.19		Indenture, dated as of April 1, 2010, among CONSOL Energy, Inc., the Subsidiary Guarantors named therein and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.2 to Form 8-K (file no. 001-14901) filed on April 2, 2010.

4.20		Supplemental Indenture, dated as of April 30, 2010, among Dominion Exploration & Production, Inc., Dominion Reserves, Inc., Dominion Coalbed Methane, Inc., Dominion Appalachian Development, LLC, Dominion Appalachian Development Properties, LLC, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.6 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.

4.21		Supplemental Indenture No. 2, dated as of June 16, 2010, among Cardinal States Gathering Company, CNX Gas Company LLC, CNX Gas Corporation, Coalfield Pipeline Company, Knox Energy, LLC, MOB Corporation, CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee, with respect to the 8.25% Senior Notes due 2020, incorporated by reference to Exhibit 4.7 to Form 8-K/A (file no. 001-14901) filed on August 6, 2010.

4.22		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 (file no. 001-14901) filed on December 22, 2003.

4.23		Registration Rights Agreement, dated as of April 1, 2010, by and among CONSOL Energy Inc., the Guarantors listed on Schedule I attached thereto and Banc of America Securities LLC, as Representative of the Initial Purchasers, incorporated by reference to Exhibit 4.3 to From 8-K (file no. 001-14901) filed on April 2, 2010.

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 (file no. 001-14901) for the quarter ended June 30, 2003, filed on August 13, 2003.

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10.2		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.

10.3		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.

10.4		Third Amendment to the Purchase and Sale Agreement, dated as of March 12, 2010, among CNX Marine Terminals Inc., CONSOL Energy Inc., CONSOL Energy Sales Company, CONSOL of Kentucky Inc., CONSOL Pennsylvania Coal Company LLC, Consolidated Coal Company, Eighty-Four Mining Company, Fola Coal Company, L.L.C., Island Creek Coal Company, Keystone Coal Mining Corporation, Little Eagle Coal Company, L.L.C., McElroy Coal Company, Mon River Towing, Inc., Terry Eagle Coal Company, L.L.C., Twin Rivers Towing Company and CNX Funding Corporation, incorporated by reference to Exhibit 10.6 to Form 8-K (file no. 001-14901) filed on March 16, 2010.

10.5		Purchase Agreement, dated as of March 25, 2010, among CONSOL Energy Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several underwriters named in Schedule A thereto, incorporated by reference to Exhibit 1.1 to the Form 8-K (file no. 001-14901) filed on March 31, 2010.

10.6		Services Agreement, dated as of April 1, 2010, by and among CONSOL Energy Inc. and its subsidiaries (other than CNX Gas Corporation and its subsidiaries) and (b) CNX Gas Corporation and its subsidiaries, incorporated by reference to Exhibit 99(D)(11) of the Schedule TO filed on April 28, 2010.

10.7		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.

10.8		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.

199



10.9		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.

10.10		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.

10.11		Fourth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 27, 2009, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.4 to Form 8-K (file no. 001-14901) filed on March 16, 2010.

10.12		Fifth Amendment to Amended and Restated Receivables Purchase Agreement and Waiver, dated as of March 12, 2010, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various Sub-Servicers listed on the signature pages thereto, the Conduit Purchasers listed on the signature pages thereto, the Purchaser Agents listed on the signature pages thereto, the LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator and as LC Bank, incorporated by reference to Exhibit 10.5 to Form 8-K (file no. 001-14901) filed on March 16, 2010.

10.13		Sixth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 23, 2010, among CNX Funding Corporation, CONSOL Energy Inc., as the initial Servicer, the various 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 of the Amendment and PNC Bank, National Association, as Administrator and as LC Bank.

10.14		Commitment Letter, dated March 14, 2010, among Banc of America Bridge LLC, Banc of America Securities LLC, PNC Bank, National Association PNC Capital Markets LLC and CONSOL Energy Inc., incorporated by reference to Exhibit 10.2 to Form 8-K (file no. 001-14901) filed on March 16, 2010.

10.15		Share Tender Agreement, dated as of March 21, 2010, by and between CONSOL Energy Inc., and T. Rowe Price Associates, Inc., incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on March 22, 2010 (Film No. 10695706).

10.16		Amended and Restated Credit Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc., the Lenders Party thereto, PNC Bank, National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and Sovereign Bank, as the Co-Documentation Agents, and PNC Capital Markets LLC and Banc of America Securities LLC, as Joint Lead Arrangers, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 13, 2010.

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10.17		Amended and Restated Collateral Trust Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc. and its Designated Subsidiaries, Wilmington Trust Company, as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by reference to Exhibit 2.2 to Form 8-K (file no. 001-14901) filed on May 13, 2010.

10.18		Amended and Restated Pledge Agreement, dated as of May 7, 2010, made and entered into by each of the pledgors listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.3 to Form 8-K (file no. 001-14901) filed on May 13, 2010.

10.19		Amended and Restated Security Agreement, dated as of May 7, 2010, by and among CONSOL Energy Inc., each of the parties listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.4 to Form 8-K (file no. 001-14901) filed on May 13, 2010.

10.20		Patent, Trademark and Copyright Security Agreement, dated as of June 27, 2007, by and among 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, as Collateral Trustee.

10.21		First Amendment to Amended and Restated Patent, Trademark and Copyright Security Agreement, dated as of May 7, 2010, by and among each of the pledgors listed on the signature pages thereto and each other persons and entities that become bound thereto from time to time by joinder, assumption, or otherwise and Wilmington Trust Company, as Collateral Trustee, incorporated by reference to Exhibit 2.5 to Form 8-K (file no. 001-14901) filed on May 13, 2010.

10.22		Amended and Restated Continuing Agreement of Guaranty and Suretyship, dated as of May 7, 2010, jointly and severally given by each of the undersigned thereto and each of the other persons which become Guarantors thereunder from time to time in favor of PNC Bank, National Association, in its capacity as the administrative agent for the Lenders, in connection with that certain Amended and Restated Credit Agreement, as defined therein.

10.23		Continuing Agreement of Guaranty and Suretyship (CNX Gas and Certain of its Subsidiaries), dated as of June 16, 2010, jointly and severally given by each of the undersigned thereto and each of the other persons which become Guarantors thereunder from time to time in favor of PNC Bank, National Association, in its capacity as the administrative agent for the Lenders, in connection with that certain Amended and Restated Credit Agreement, as defined therein.

10.24		Credit Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation, the guarantors party thereto, the lender parties thereto, PNC Bank National Association, as the Administrative Agent, Bank of America, N.A., as the Syndication Agent, The Bank of Nova Scotia, The Royal Bank of Scotland PLC and Wells Fargo Bank, National Association, as the Co-Documentation Agents and PNC Capital Markets, Inc. and Bank of America Securities LLC, as Bookrunners and Joint Lead Arrangers, incorporated by reference to Exhibit 10.36 to the CNX Gas Corporation Form 8-K (file no. 001-14901) filed on May 13, 2010.

10.25		Collateral Trust Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation, its Designated Subsidiaries, Wilmington Trust Company, as Corporate Trustee and David A. Vanaskey, as Individual Trustee, incorporated by reference to Exhibit 2.1 to the CNX Gas Corporation Form 8-K (file no. 001-14901) filed on May 13, 2010.

10.26		Pledge Agreement, dated as of May 7, 2010, 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, as Collateral Trustee, incorporated by reference to Exhibit 2.2 to the CNX Gas Corporation Form 8-K (file no. 001-14901) filed on May 13, 2010.

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10.27		Security Agreement, dated as of May 7, 2010, by and among CNX Gas Corporation and each of the undersigned parties 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, as Collateral Trustee, incorporated by reference to Exhibit 2.3 to the CNX Gas Corporation Form 8-K (file no. 001-14901) filed on May 13, 2010.

10.28		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 (file no. 001-14901), filed on February 17, 2009.

10.29		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 (file no. 001-14901) filed on May 7, 2007.

10.30		Consulting Agreement dated, as July 1, 2010, by and between CONSOL Energy Inc., and John Whitmire, incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended September 30, 2010, filed on November 1, 2010.

10.31		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 (file no. 001-14901) filed on March 10, 2009.

10.32		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 (file no. 001-14901) for the quarter ended September 30, 2007, filed on November 1, 2007.

10.33		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 (file no. 001-14901) filed on August 24, 2007.

10.34		Offer Letter, dated February 14, 2005, between CONSOL Energy Inc. and P. Jerome Richey, incorporated by reference to Exhibit 10.58 to Form 8-K (file no. 001-14901), filed on March 4, 2005.

10.35		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 (file no. 001-14901), filed on February 17, 2009.

10.36		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 (file no. 001-14901), filed on February 17, 2009.

10.37		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 (file no. 001-14901), filed on February 17, 2009.

10.38		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 (file no. 001-14901), filed on February 17, 2009.

10.39		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 (file no. 001-14901), filed on February 17, 2009.

10.40		Change in Control Agreement by and among CNX Gas Corporation, CONSOL Energy Inc. and Robert Pusateri, incorporated by reference to Exhibit 10.8 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009

10.41		Change in Control Severance Agreement, dated as of December 2, 2008 and amended as of February 23, 2010, between CONSOL Energy Inc. and Robert Pusateri, incorporated by reference to Exhibit 10.9 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2010, filed on May 4, 2010.

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10.42		Form of Indemnification Agreement for Directors and Executive Officers of CONSOL Energy Inc., incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.

10.43		Form of Indemnification Agreement for Directors and Executive Officers of CNX Gas Corporation, incorporated by reference to Exhibit 10.7 to Form 10-Q (file no. 001-14901) for the quarter ended June 30, 2009, filed on August 3, 2009.

10.44		Equity Incentive Plan, As Amended and Restated, effective April 28, 2009, incorporated by reference to Exhibit 10.1 to the Form 8-K (file no. 001-14901) filed on May 1, 2009.

10.45		Executive Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on May 1, 2008.

10.46		Amended and Restated Long-Term Incentive Program (2007-2009), 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.

10.47		Long-Term Incentive Program (2008 – 2010), incorporated by reference to Exhibit 10.6 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.

10.48		Long-Term Incentive Program (2009-2011), incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2009, filed on April 27, 2009.

10.49		Long-Term Incentive Program (2010 - 2012), incorporated by reference to Exhibit 10.8 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2010, filed on May 4, 2010.

10.50		Non-Employee Director Option Grant Notice, as amended, incorporated by reference to Exhibit 10.84 to the Form 8-K (file no. 001-14901) filed on October 24, 2005.

10.51		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.

10.52		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 (file no. 333-157894) filed on June 26, 2009.

10.53		Form of Employee Non-Qualified Performance Stock Option Agreement, incorporated by reference to Exhibit 10.1 to Form 8-K (file no. 001-14901) filed on June 21, 2010.

10.54		Form of Restricted Stock Unit Award Agreement for 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.

10.55		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 (file no. 333-157894) filed on June 26, 2009.

10.56		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.

10.57		Form of Election and Restricted Stock Unit Award Agreement (Exchange Offer), incorporated by reference to Exhibit 99.1 to Form S-4 (file no. 333-157894) filed on June 26, 2009.

10.58		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 (file no. 001-14901) for the quarter ended March 31, 2009, filed on April 27, 2009.

203



10.59		Form of 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 (file no. 001-14901) for the quarter ended March 31, 2009, filed on April 27, 2009.

10.60		Summary of Non-Employee Director Compensation.

10.61		Directors Deferred Compensation Plan (1999 Plan), incorporated by reference to Exhibit 10.1 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.

10.62		Hypothetical Investment Election Form Relating to Directors’ Deferred Compensation Plan (1999 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.

10.63		Directors’ Deferred Fee Plan (2004 Plan) (Amended and Restated on December 4, 2007), incorporated by reference to Exhibit 10.3 to Form 10-Q (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.

10.64		Hypothetical Investment Election Form Relating to Directors’ Deferred Fee Plan (2004 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.

10.65		Form of Director Deferred Stock Unit Grant Agreement, incorporated by reference to Exhibit 10.95 to the Form 8-K (file no. 001-14901) filed on May 8, 2006.

10.66		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 (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.

10.67		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 (file no. 001-14901) for the quarter ended March 31, 2008, filed on April 30, 2008.

10.68		Amended and Restated Retirement Restoration Plan of CONSOL Energy Inc., incorporated by reference to Exhibit 10.30 to Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.

10.69		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 (file no. 001-14901) filed on September 11, 2009.

10.70		CNX Gas Corporation Equity Incentive Plan, as amended, incorporated by reference to Exhibit 10.23 to the CNX Gas Corporation Form 10-K for the year ended December 31, 2008 (file no. 001-14901), filed on February 17, 2009.

10.71		Form of Award Agreements under CNX Gas Corporation Equity Incentive Plan, as amended, incorporated by reference to Exhibit 10.5 to Amendment No. 1 to the Form S-1 (file no. 333-127483) for CNX Gas Corporation, filed on September 29, 2005.

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 (file no. 001-14901) filed on December 5, 2008.

21		Subsidiaries of CONSOL Energy Inc.

23.1		Consent of Ernst & Young LLP.

23.2		Consent of Netherland Sewell & Associates, Inc.

23.3		Consent of Schlumberger Data and Consulting Services.

204



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, 2010 furnished in XBRL).

Instruments relating to the Baltimore Port Facility 5.75% Industrial Development Bonds due 2025 have not been filed and a copy thereof will be furnished to the Securities and Exchange Commission upon request.

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 and to the commission subsequent to the filing of this Form 10-K.

In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.

205

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 10th day of February, 2011.


CONSOL ENERGY INC.

By:		/s/ J. BRETT HARVEY
		J. Brett Harvey,
		Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 10th day of February, 2011, by the following persons on behalf of the registrant in the capacities indicated:


Signature		Title

/s/ J. BRETT HARVEY J. Brett Harvey		Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)

/s/ WILLIAM J. LYONS William J. Lyons		Chief Financial Officer and Executive Vice President (Principal Financial Officer)

/s/ JOHN L. WHITMIRE John L. Whitmire		Vice Chairman of the Board

/s/ PHILIP W. BAXTER Philip W. Baxter		Lead Independent Director

/s/ JAMES E. ALTMEYER, SR. James E. Altmeyer, Sr.		Director

/s/ WILLIAM E. DAVIS William E. Davis		Director

/s/ RAJ K. GUPTA Raj K. Gupta		Director

/s/ PATRICIA A. HAMMICK Patricia A. Hammick		Director

/s/ DAVID C. HARDESTY, JR. David C. Hardesty, Jr.		Director

/s/ JOHN T. MILLS John T. Mills		Director

/s/ WILLIAM P. POWELL William P. Powell		Director

/s/ JOSEPH T. WILLIAMS Joseph T. Williams		Director

206

SCHEDULE II

CONSOL ENERGY INC. AND SUBSIDIARIES

Valuation and Qualifying Accounts

(Dollars in thousands)


			Additions		Deductions
	Balance at Beginning of Period		Charged to Expense		Release of Valuation Allowance			Balance at End of Period
Year Ended December 31, 2010
State operating loss carry-forwards	$	37,052	$	3,917	$	(1,225	)	$	39,744
Deferred deductible temporary differences		24,571		287		(1,934	)		22,924

Total	$	61,623	$	4,204	$	(3,159	)	$	62,668

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

207