Exhibit 99.1

Item 1. Business.

CONSOL Energy’s History

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

Historically, we rank among the largest coal producers in the United States based upon total revenue, net income and operating cash flow. Our production of approximately 59 million tons of coal in 2009 accounted for approximately 6% of the total tons produced in the United States and approximately 13% of the total tons produced east of the Mississippi River during 2009. We are one of the premier coal producers in the United States by several measures:

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

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

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

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

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

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

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

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

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

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

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

Industry Segments

CONSOL Energy has two principal business units: Coal and Gas. The principal activities of the Coal unit are mining, preparation and marketing of steam coal, sold primarily to power generators and metallurgical coal, sold to metal and coke producers. The Coal unit includes three reportable segments. These reportable segments are Steam, Low 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, 2009, the Steam aggregated segment includes the following mines or type of coal sold: Bailey, Blacksville #2, Buchanan steam, Emery, Enlow Fork, Fola Complex, Jones Fork Complex, Loveridge, McElroy, Miller Creek Complex, Mine 84, Robinson Run and Shoemaker. For the year ended December 31, 2009, the Low Volatile Metallurgical aggregated segment includes the Buchanan metallurgical sales and the Amonate Complex. The Other Coal segment includes our purchased coal activities, idled mine activities, as well as various other activities assigned to the coal segment but not allocated to each individual mine or type of coal sold. The principal activity of the Gas unit is to produce pipeline quality methane gas for sale primarily to gas wholesalers. The Gas unit includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus, Conventional and Other Gas. For the years ended December 31, 2008 and 2007, the Marcellus and Conventional segments were insignificant to the Gas unit with sales representing less than 1% of total sales volumes. The Other Gas segment includes our purchased gas activities as well as various other activities assigned to the gas segment 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, including rentals of buildings and flight operations. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years ended December 31, 2009, 2008 and 2007 is included in Note 25 of Notes to Audited Consolidated Financial Statements included as Item 8 in Part II of this Form 8-K.

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Coal Operations

Mining Complexes

During the year ended December 31, 2009, CONSOL Energy had 16 active mining complexes, including a 49% equity affiliate, all located in the United States.

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

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

CONSOL ENERGY MINING COMPLEXES

Proven and Probable Assigned and Accessible Coal Reserves as of December 31, 2009 and 2008

Mine/Reserve	Location	Reserve Class	Coal Seam	Average Seam Thickness (feet)	As Received Heat Value(1) (Btu/lb)		Recoverable Reserves(2)					Recoverable Reserves (tons in Millions) 12/31/2008
					Typical	Range	Owned (%)		Leased (%)		Tons in Millions 12/31/2009
ASSIGNED—OPERATING
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)
Enlow Fork	Enon, PA	Assigned	Pittsburgh	5.4	12,940	12,860 – 13,060	100	%	—	%	48.9	160.3
		Accessible	Pittsburgh	5.3	12,900	12,830 – 13,000	79	%	21	%	197.9	185.3
Bailey	Enon, PA	Assigned	Pittsburgh	5.7	12,950	12,860 – 13,060	53	%	47	%	74.5	33.4
		Accessible	Pittsburgh	5.8	12,900	12,830 – 13,000	82	%	18	%	382.8	144.2
Mine 84	Eighty Four, PA	Assigned	Pittsburgh	5.4	13,120	12,950 – 13,250	100	%	—	%	11.3	26.9
		Accessible	Pittsburgh	5.8	13,050	12,880 – 13,180	66	%	34	%	68.3	86.7
McElroy	Glen Easton, WV	Assigned	Pittsburgh	5.9	12,570	12,450 – 12,650	100	%	—	%	195.0	201.5
		Accessible	Pittsburgh	5.8	12,530	12,410 – 12,610	94	%	6	%	153.0	69.0
Shoemaker	Moundsville, WV	Assigned	Pittsburgh	5.6	12,200	11,700 – 12,300	100	%	—	%	48.4	60.2
		Accessible	Pittsburgh	5.6	12,250	11,990 – 12,390	100	%	—	%	27.8	35.8
Loveridge	Fairview, WV	Assigned	Pittsburgh	7.5	13,150	13,070 – 13,370	84	%	16	%	37.9	47.0
		Accessible	Pittsburgh	7.6	13,100	13,020 – 13,320	95	%	5	%	13.6	25.7
Robinson Run	Shinnston, WV	Assigned	Pittsburgh	7.3	12,940	12,600 – 13,300	88	%	12	%	58.2	67.2
		Accessible	Pittsburgh	6.8	12,940	12,600 – 13,300	55	%	45	%	156.7	154.1
Blacksville #2	Wana, WV	Assigned	Pittsburgh	6.7	13,060	12,850 – 13,250	87	%	13	%	29.1	32.2
		Accessible	Pittsburgh	6.9	13,100	12,890 – 13,290	99	%	1	%	16.5	16.5
Harrison Resources(3)	Cadiz, OH	Assigned	Multiple	4.5	11,570	11,350 – 11,850	100	%	—	%	9.2	9.6
Central Appalachia (Virginia, Southern West Virginia, Eastern Kentucky)
Buchanan	Mavisdale, VA	Assigned	Pocahontas 3	5.7	13,980	13,700 – 14,200	19	%	81	%	68.4	39.9
		Accessible	Pocahontas 3	6.0	13,930	13,650 – 14,150	10	%	90	%	37.0	64.4
AMVEST—Fola Complex	Bickmore, WV	Assigned	Multiple	6.1	12,380	12,250 – 12,550	96	%	4	%	101.7	104.0
AMVEST—Terry Eagle Complex	Bickmore, WV	Assigned	Multiple	3.2	13,300	13,200 – 13,350	—	%	100	%	22.7	22.8
Jones Fork Complex	Mousie, KY	Assigned	Multiple	3.2	12,530	12,450 – 12,650	74	%	26	%	35.1	35.8
		Accessible	Multiple	3.4	12,330	12,250 – 12,450	100	%	—	%	1.4	1.4
Amonate Complex	Amonate, VA	Assigned	Multiple	3.8	13,100	12,850 – 13,350	70	%	30	%	19.6	19.6
Miller Creek Complex	Delbarton, WV	Assigned	Multiple	8.1	12,000	11,600 – 12,650	17	%	83	%	10.0	13.2
Western U.S. (Utah)
Emery	Emery Co., UT	Assigned	Ferron I	7.5	12,260	12,000 – 13,000	79	%	21	%	16.9	16.9
Total Assigned Operating and Accessible							78	%	22	%	1,841.9	1,673.6

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(1) The heat value shown for assigned reserves is based on the quality of coal mined and processed during the year ended December 31, 2009. The heat value shown for accessible reserves is based on the same mining and processing methods as for the assigned reserves with adjustments made based on the variability found in exploration drill core samples. The heat values given have been adjusted to include moisture that may be added during mining or processing and for dilution by rock lying above or below the coal seam.

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

(3) Harrison Resources is an equity affiliate in which CONSOL Energy owns a 49% interest. Reserves reported equal CONSOL Energy’s 49% proportionate interest in Harrison Resources’ reserves.

Excluded from the table above are approximately 109.2 million tons of reserves at December 31, 2009 that are assigned to projects that have not produced coal in 2009 or 2008. These assigned reserves are in the Northern Appalachia (northern West Virginia), Central Appalachia (Virginia and eastern Kentucky) and Illinois Basin (Illinois) regions. These reserves are approximately 52% owned and 48% leased.

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

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

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

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

Coal Reserves

At December 31, 2009, CONSOL Energy had an estimated 4.5 billion tons of proven and probable reserves. Reserves are the portion of the proven and probable tonnage that meet CONSOL Energy’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels.

Reserves are defined in Securities and Exchange Commission (SEC) Industry Guide 7 as follows:

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

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

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

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

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

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

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

Our estimate of proven and probable coal reserves has been determined by CONSOL Energy’s geologists and mining engineers. Our coal reserves are periodically reviewed by an independent third party consultant. The independent consultant has reviewed the procedures used by us to prepare our internal estimates, verified the accuracy of approximately 97% of our property reserve estimates and retabulated reserve groups according to standard classifications of reliability.

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

CONSOL Energy’s reserves are located in northern Appalachia (62%), central Appalachia (14%), the mid-western United States (18%), the western United States (4%), and in western Canada (2%) at December 31, 2009.

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

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

	As Received Heat Value(1) (Btu/lb)	Recoverable Reserves 12/31/09(2)					Recoverable Reserves (tons in millions) 12/31/2008
Coal Producing Region		Owned (%)		Leased (%)		Tons (in millions)
Northern Appalachia (Pennsylvania, Ohio, Northern West Virginia)	11,400 – 13,500	70	%	30	%	1,239.7	1,437.1
Central Appalachia (Virginia, Southern West Virginia, Eastern Kentucky)	11,900 – 14,200	43	%	57	%	301.4	264.5
Illinois Basin (Illinois, Western Kentucky, Indiana)	11,500 – 11,900	43	%	57	%	780.6	780.6
Western U.S. (Wyoming)	9,400	100	%	—	%	169.1	169.1
Western Canada (Alberta)	12,400 – 12,900	—	%	100	%	77.9	77.9
Total		62	%	38	%	2,568.7	2,729.2

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

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

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The following table summarizes our proven and probable reserves as of December 31, 2009 by region and type of coal or sulfur content (sulfur content per million British thermal units). Proven and probable reserves include both assigned and unassigned reserves. The table classifies bituminous coal by rank. Rank (High volatile A, B and C) of bituminous coals are classified on the basis of heat value. The table also classifies bituminous coals as medium and low volatile which are classified on the basis of fixed carbon and volatile matter. Coal is ranked by the degree of alteration it has undergone since the initial deposition of the organic material. The lowest ranked coal, lignite, has undergone less transformation than the highest ranked coal, anthracite. From the lowest to the highest rank, the coals are: lignite; sub-bituminous; bituminous and anthracite. The ranking is determined by measuring the fixed carbon to volatile matter ratio and the heat content of the coal. As rank increases, the amount of fixed carbon increases, volatile matter decreases, and heat content increases. Bituminous coals are further characterized by the amount of volatile matter present. Bituminous coals with high volatile matter content are also ranked. High volatile “A” bituminous coals have higher heat content than high volatile “C” bituminous coals. These characterizations of coal allow a user to predict the behavior of a coal when burned in a boiler to produce heat or when it is heated in the absence of oxygen to produce coke for steel production.

CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES

BY PRODUCING REGION AND PRODUCT (IN MILLIONS OF TONS) AS OF DECEMBER 31, 2009

	£1.20 lbs						> 1.20 £ 2.50 lbs						> 2.50 lbs						Total		Percentage By Region
	S02/MMBtu						S02/MMBtu						S02/MMBtu
By Region	Low Btu		Med Btu		High Btu		Low Btu		Med Btu		High Btu		Low Btu		Med Btu		High Btu
Northern Appalachia:
Metallurgical:
High Vol A Bituminous	—		—		—		—		—		162.3		—		—		—		162.3		3.6	%
Steam:
High Vol A Bituminous	—		—		—		—		—		111.0		54.4		123.4		2,328.0		2,616.8		57.9	%
Low Vol Bituminous	—		—		—		—		—		33.6		—		—		—		33.6		0.7	%
Region Total	—		—		—		—		—		306.9		54.4		123.4		2,328.0		2,812.7		62.2	%
Central Appalachia:
Metallurgical:
High Vol A Bituminous	33.6		4.9		22.6		—		—		18.3		—		—		1.3		80.7		1.8	%
Med Vol Bituminous	0.5		2.8		82.3		—		—		—		—		—		—		85.6		1.9	%
Low Vol Bituminous	—		—		124.5		2.3		—		26.2		—		—		—		153.0		3.4	%
Steam:
High Vol A Bituminous	38.3		73.4		14.1		61.6		46.2		61.7		0.8		2.5		5.2		303.8		6.8	%
Region Total	72.4		81.1		243.5		63.9		46.2		106.2		0.8		2.5		6.5		623.1		13.9	%
Midwest—Illinois Basin:
Steam:
High Vol B Bituminous	—		—		—		—		79.4		—		—		460.6		—		540.0		12.0	%
High Vol C Bituminous	—		—		—		—		159.5		—		108.3		—		—		267.8		5.9	%
Region Total	—		—		—		—		238.9		—		108.3		460.6		—		807.8		17.9	%
Northern Powder River Basin:
Steam:
Sub bituminous B	—		—		169.1		—		—		—		—		—		—		169.1		3.7	%
Region Total	—		—		169.1		—		—		—		—		—		—		169.1		3.7	%
Utah—Emery Field:
High Vol B Bituminous	—		16.9		—		—		12.3		—		—		—		—		29.2		0.6	%
Region Total	—		16.9		—		—		12.3		—		—		—		—		29.2		0.6	%
Western Canada:
Metallurgical:
Med Vol Bituminous	30.2		47.7		—		—		—		—		—		—		—		77.9		1.7	%
Region Total	30.2		47.7		—		—		—		—		—		—		—		77.9		1.7	%
Total Company	102.6		145.7		412.6		63.9		297.4		413.1		163.5		586.5		2,334.5		4,519.8		100.0	%
Percent of Total	2.3	%	3.2	%	9.1	%	1.4	%	6.6	%	9.1	%	3.6	%	13.0	%	51.7	%	100.0	%

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CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES BY PRODUCT

(MILLIONS OF TONS) AS OF DECEMBER 31, 2009

The following table classifies CONSOL Energy coals by rank, projected sulfur dioxide emissions and heating value (British thermal units per pound). The table also classifies bituminous coals as medium and low volatile which is based on fixed carbon and volatile matter.

	£1.20 lbs						> 1.20 £ 2.50 lbs						> 2.50 lbs
	S02/MMBtu						S02/MMBtu						S02/MMBtu
By Product	Low Btu		Med Btu		High Btu		Low Btu		Med Btu		High Btu		Low Btu		Med Btu		High Btu		Total		Percentage By Product
Metallurgical:
High Vol A Bituminous	33.6		4.9		22.6		—		—		180.6		—		—		1.3		243.0		5.4	%
Med Vol Bituminous	30.7		50.5		82.3		—		—		—		—		—		—		163.5		3.6	%
Low Vol Bituminous	—		—		124.5		2.3		—		26.2		—		—		—		153.0		3.4	%
Total Metallurgical	64.3		55.4		229.4		2.3		—		206.8		—		—		1.3		559.5		12.4	%
Steam:
High Vol A Bituminous	38.3		73.4		14.1		61.6		46.2		172.7		55.2		125.9		2,333.2		2,920.6		64.6	%
High Vol B Bituminous	—		16.9		—		—		91.7		—		—		460.6		—		569.2		12.6	%
High Vol C Bituminous	—		—		—		—		159.5		—		108.3		—		—		267.8		5.9	%
Low Vol Bituminous	—		—		—		—		—		33.6		—		—		—		33.6		0.8	%
Sub bituminous B	—		—		169.1		—		—		—		—		—		—		169.1		3.7	%
Total Steam	38.3		90.3		183.2		61.6		297.4		206.3		163.5		586.5		2,333.2		3,960.3		87.6	%
Total	102.6		145.7		412.6		63.9		297.4		413.1		163.5		586.5		2,334.5		4,519.8		100.0	%
Percent of Total	2.3	%	3.2	%	9.1	%	1.4	%	6.6	%	9.1	%	3.6	%	13.0	%	51.7	%	100.0	%

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

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

Compliance Compared to Non-Compliance Coal

Coals are sometimes characterized as compliance or non-compliance coal. The term compliance coal, as it is commonly used in the coal industry, refers to compliance only with sulfur dioxide emissions standards and indicates that when burned, the coal will produce emissions that will not exceed 1.2 pounds of sulfur dioxide per million British thermal units (1.2lb S02/MM BTU). A coal considered a compliance coal for meeting sulfur dioxide standards may not meet an emission standard for a different pollutant such as mercury. Moreover, the term compliance coal is always used with reference to the then-current regulatory limit. Clean air regulations that further restrict sulfur dioxide emissions will likely reduce significantly the amount of coal that can be used without post-combustion emission control technologies. Currently, a compliance coal will meet the power plant emission standard of 1.2 lb S02/MM BTU of fuel consumed. At December 31, 2009, 0.7 billion tons, or 15%, of our coal reserves met the current standard as a compliance coal. It is possible that no coal will be considered compliance coal with emission standards restricted to a level that requires emissions-control technology to be used regardless of the coal’s sulfur content. In many cases, our customers have responded to compliance coal requirements by retrofitting flue gas desulfurization systems (scrubbers) to existing power plants. Because these systems remove sulfur dioxide before it is emitted into the atmosphere, our customers are less concerned about the sulfur content of our coal.

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

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Production

In the year ended December 31, 2009, 91% of CONSOL Energy’s production came from underground mines and 9% from surface mines. Where the geology is favorable and reserves are sufficient, CONSOL Energy employs longwall mining systems in our underground mines. For the year ended December 31, 2009, 87% of our production came from mines equipped with longwall mining systems. Underground longwall systems are highly mechanized, capital intensive operations. Mines using longwall systems have a low variable cost structure compared with other types of mines and can achieve high productivity levels compared with those of other underground mining methods. Because CONSOL Energy has substantial reserves readily suitable to these operations, CONSOL Energy believes that these longwall mines can increase capacity at low incremental cost.

The following table shows the production, in millions of tons, for CONSOL Energy’s mines in the years ended December 31, 2009, 2008 and 2007, the location of each mine, the type of mine, the type of equipment used at each mine and the year each mine was established or acquired by us.

Mine	Location	Mine Type	Mining Equipment	Transportation	Tons Produced (in millions)			Year Established or Acquired
					2009	2008	2007
Northern Appalachia
Enlow Fork	Enon, Pennsylvania	U	LW/CM	R R/B	11.1	11.1	11.2	1990
Bailey	Enon, Pennsylvania	U	LW/CM	R R/B	10.4	10.0	9.9	1984
McElroy	Glen Easton, West Virginia	U	LW/CM	B	9.9	9.6	9.7	1968
Loveridge	Fairview, West Virginia	U	LW/CM	R T	6.0	5.2	6.6	1956
Robinson Run	Shinnston, West Virginia	U	LW/CM	R CB	5.6	5.6	6.5	1966
Blacksville 2(1)	Wana, West Virginia	U	LW/CM	R R/B T	3.8	5.6	5.1	1970
Mine No. 84(1)	Eighty Four, Pennsylvania	U	LW/CM	R R/B T	0.5	1.8	3.6	1998
Shoemaker(2)	Moundsville, West Virginia	U	LW/CM	B	0.4	1.1	—	1966
Harrison Resource Corporation(3)(4)	Cadiz, Ohio	S	S/L	R T	0.4	0.2	0.1	2007
Central Appalachia
Miller Creek Complex(3)	Delbarton, West Virginia	U/S	CM/S/L	T	3.2	3.1	1.4	2004
AMVEST-Fola Complex(1)(3)(5)	Bickmore, West Virginia	U/S	A S/L CM	R	3.0	3.9	1.8	2007
Buchanan(1)(6)	Mavisdale, Virginia	U	LW/CM	R	2.8	3.5	2.8	1983
Jones Fork Complex(1)(3)	Mousie, Kentucky	U/S	CM	R T	1.1	2.5	3.1	1992
Amonate Complex(1)	Amonate, Virginia	U/S	CM/S/L	R T	—	0.4	0.6	1925
AMVEST-Terry Eagle Complex(5)	Jodie, West Virginia	U/S	CM A S/L	R T	—	0.4	0.1	2007
Mill Creek(3)(7)	Deane, Kentucky	U/S	CM	R	—	—	1.1	1994
Western U.S.
Emery	Emery County, Utah	U	CM	T	1.2	1.1	1.0	1945

A= Auger

S = Surface

U = Underground

LW = Longwall

CM = Continuous Miner

S/L = Stripping Shovel and Front End Loaders

R = Rail

B = Barge

R/B = Rail to Barge

T = Truck

CB = Conveyor Belt

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

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

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

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

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

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

(7) Mine was sold in February 2008.

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

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

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

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the daily maintenance of the mine roof that underground haulage systems require allowing manpower to be reduced or redeployed to more productive work. Mine safety is expected to be enhanced by the overland belts because older underground belt areas will be sealed.

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

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

The following table sets forth, with respect to properties that we lease to other coal operators, the total royalty tonnage, acreage leased and the amount of income (net of related expenses) we received from royalty payments for the years ended December 31, 2009, 2008 and 2007.

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

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

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

MAJOR U.S. UNDERGROUND COAL MINES—2008

In millions of tons

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

Source: National Mining Association

Marketing and Sales

We sell coal produced by our mining complexes and additional coal that is purchased by us for resale from other producers. We maintain United States sales offices in Atlanta, Philadelphia and Pittsburgh. In addition, we sell coal through agents and to brokers and unaffiliated trading companies. In 2009, we sold 58.1 million tons of coal, including our portion of equity affiliates. Eighty-eight percent (88%) of these sales were sold in domestic markets. Our direct sales to domestic electricity generators represented 83% of our total tons sold in 2009. We had approximately 90 customers in 2009. During 2009, no coal customers individually accounted for more than 10% of total revenue. However, the top four coal customers accounted for more than 25% of our total revenues.

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Coal Contracts

We sell coal to customers under arrangements that are the result of both bidding procedures and unsolicited offers leading to extensive negotiations. We sell coal for terms that range from a single shipment to multi-year agreements for millions of tons. During the year ended December 31, 2009, approximately 90% of the coal we produced was sold under contracts with terms of one year or more. The pricing mechanisms under our multiple-year agreements typically consist of contracts with one or more of the following pricing mechanisms:

• Fixed price contracts with pre-established prices; or

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

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

Several contracts provide the opportunity to periodically adjust the contract prices. Contract prices may be adjusted as often as quarterly based upon indices which are pre-negotiated. Most of our contracts have terms no longer than five years. However, some of our contracts range in term from seven years to twenty years.

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

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

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

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

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

Distribution

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

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

Competition

The United States coal industry is highly competitive, with numerous producers selling into all markets that use coal. CONSOL Energy competes against other large producers and hundreds of small producers in the United States and overseas. The five largest producers are estimated by the 2008 National Mining Association Survey to have produced approximately 53% (based on tonnage produced) of the total United States production in 2008. The U.S. Department of Energy reported 1,435 active coal mines in the United States in 2008, the latest year for which government statistics are available. Demand for our coal by our principal customers is affected by:

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

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• coal quality;

• transportation costs from the mine to the customer; and

• the reliability of fuel supply.

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

Gas Operations

Our gas operations are primarily conducted by CNX Gas Corporation (CNX Gas), an 83.3% owned subsidiary of CONSOL Energy. Information presented below is 100% of CNX Gas’ basis; it does not include 16.7% noncontrolling interest reduction. CNX Gas primarily produces coalbed methane, which is gas that resides in coal seams. In the eastern United States, conventional natural gas fields typically are located in various types of sedimentary formations at depths ranging from 2,000 to 15,000 feet. Exploration companies often put their capital at risk by searching for gas in commercially exploitable quantities at these depths. By contrast, gas in the coal seams that we drill or anticipate drilling is typically in formations less than 2,500 feet deep which are usually better defined than deeper formations. CNX Gas believes that this contributes to lower exploration costs than those incurred by producers that operate in deeper, less defined formations. However, we have continued to increase our exploratory efforts in the shale and deeper formations.

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

Areas of Operation

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

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

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

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

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

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

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

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

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

Central Appalachia

Virginia Operations CBM

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

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

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

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

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

Virginia Operations Shale and Tight Sands

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

Tennessee

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

Northern Appalachia

Mountaineer CBM

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

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

Nittany CBM

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

Marcellus Shale

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

Shallow Oil and Gas

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

Others

Cardinal Shale

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

Illinois Basin CBM

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

Other Acreage

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

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Summary of Properties as of December 31, 2009

	Central Appalachia		Northern Appalachia		Other		Total
Estimated Net Proved Reserves (billion cubic feet equivalent)	1,551		332		28		1,911
Percent Developed	56	%	42	%	100	%	54	%
Net Producing Wells (including gob wells)	3,363		492		71		3,926
Net Proved Developed CBM Acres	148,988		92,533		—		241,521
Net Proved Undeveloped CBM Acres	34,433		12,209		—		46,642
Net Unproved CBM Acres(1)	548,904		1,046,088		674,162		2,269,154
Total Net CBM Acres	732,325		1,150,830		674,162		2,557,317
Net Proved Developed Oil & Gas Acres	8,129		5,005		98		13,232
Net Proved Undeveloped Oil & Gas Acres	5,936		1,720		—		7,656
Net Unproved Oil & Gas Acres(1)	483,202		248,094		399,040		1,130,336
Total Net Oil & Gas Acres	497,267		254,819		399,138		1,151,224

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

Development Wells (Net)

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

	For the Year Ended December 31,
	2009	2008	2007
Central Appalachia	202	321	294
Northern Appalachia	45	213	76
Total	247	534	370

Exploratory Wells (Net)

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

	As of December 31,
	2009			2008			2007
	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.
Central Appalachia	6	—	4	8	—	18	3	—	—
Northern Appalachia	5	1	2	6	—	20	—	—	—
Other	—	—	—	1	3	—	1	—	5
Total	11	1	6	15	3	38	4	—	5

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Summary of Other Operating Data

Production

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

	For the Year Ended December 31,
	2009	2008	2007
Total Produced (million cubic feet)	94,415	76,562	58,249

Average Sales Prices and Lifting Costs

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

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

Productive Wells and Acreage

Most of our development wells and proved acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied. The following table sets forth, at December 31, 2009, the number of CNX Gas producing wells, developed acreage and undeveloped acreage:

	Gross	Net(1)
Producing Wells (including gob wells)	5,240	3,926
Proved Developed Acreage	260,327	254,753
Proved Undeveloped Acreage	56,090	54,298
Unproven Acreage	3,957,174	3,399,490
Total Acreage	4,273,591	3,708,541

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

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

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

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

Reserves

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

	Net Reserves (Million cubic feet equivalent) as of December 31,
	2009		2008		2007
	Consolidated Operations	Affiliates	Consolidated Operations	Affiliates	Consolidated Operations	Affiliates
Proved developed reserves	1,040,257	—	783,290	—	667,726	3,584
Proved undeveloped reserves	871,134	—	638,756	—	672,183	—
Total proved developed and undeveloped reserves	1,911,391	—	1,422,046	—	1,339,909	3,584

Discounted Future Net Cash Flows

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

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

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

Reconciliation of PV-10 to Standardized Measure

	As of December 31,
	2009			2008			2007
	(Dollars in millions)
Future cash inflows	$	7,975		$	8,857		$	9,509
Future production costs		(3,123	)		(3,526	)		(3,005	)
Future development costs (including abandonments)		(996	)		(794	)		(636	)
Future net cash flows (pre-tax)		3,856			4,537			5,868
10% discount factor		(2,376	)		(2,533	)		(3,580	)
PV-10 (Non-GAAP measure)		1,480			2,004			2,288
Undiscounted income taxes		(1,465	)		(1,714	)		(2,259	)
10% discount factor		879			928			1,361
Discounted income taxes		(586	)		(786	)		(898	)
Standardized GAAP measure	$	894		$	1,218		$	1,390

Competition

We operate primarily in the eastern United States. We believe that the gas market is highly fragmented and not dominated by any single producer. We believe that several of our competitors have devoted far greater resources than we have to gas exploration and development. We believe that competition within our market is based primarily on gas commodity trading fundamentals and pipeline transportation availability to the diverse market opportunities.

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Power Generation

Through a joint venture with Allegheny Energy Supply Company, LLC, an affiliate of one of our largest coal customers, CNX Gas owns a 50% interest in an 88-megawatt, gas-fired electric generating facility. This facility is used for meeting peak load demands for electricity. The facility is located in southwest Virginia and uses coalbed methane gas that we produce. Because it is a peaking power facility, it does not operate at all times of the year, but the facility does provide a potential sales outlet for CNX Gas of up to 22 million cubic feet per day.

Other

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

Land Resources

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

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

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

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

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

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

Industrial Supply Services

Fairmont Supply Company, a CONSOL Energy subsidiary, is a general-line distributor of mining and industrial supplies in the United States. Fairmont Supply has 28 customer service centers nationwide. Fairmont Supply also provides integrated supply procurement and management services. Integrated supply procurement is a materials management strategy that utilizes a single, full-line distribution to minimize total cost in the maintenance, repair and operating supply chain.

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

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

Terminal Services

In 2009, approximately 6.4 million tons of coal were shipped through CONSOL Energy’s subsidiary, CNX Marine Terminal Inc.’s, exporting terminal in the Port of Baltimore. Approximately 45% of the tonnage shipped was produced by CONSOL Energy coal mines. The terminal can either store coal or load coal directly into vessels from rail cars. It is also one of the few terminals in the United States served by two railroads, Norfolk Southern and CSX Transportation, Inc.

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River and Dock Services

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

CONSOL Energy provides dock services for our mines as well for third parties at our Alicia Dock, located on the Monongahela River in Fayette County, Pennsylvania. CONSOL Energy transfers coal from rail cars to barges for customers that receive coal on the river system.

Coal Waste Disposal Services

CONSOL Energy operates an ash disposal facility on a 61-acre site in northern West Virginia to handle ash residues for coal customers that are unable to dispose of ash on-site at their generating facilities. The ash disposal facility can process 200 tons of material per hour, and is expected to dispose of approximately 125 thousand tons of fly ash in the current contract year. CONSOL Energy has a long-term contract with a cogeneration facility to supply coal and take the residual fly ash and bottom ash. Bottom ash is disposed locally at the cogeneration facility for road construction and other purposes.

Employee and Labor Relations

At December 31, 2009, CONSOL Energy had 8,012 employees, approximately 34.5% of whom were represented by the United Mine Workers of America (UMWA). A five-year labor agreement commenced January 1, 2007. This agreement expires December 31, 2011 and provides for a 20% across-the-board wage increase over its duration. Wages increased $0.50 per hour in 2009, and will increase $0.50 per hour for 2010 through 2011. Other terms of the agreement require additional contributions to be made into the employee benefit funds. Full health-care benefits for active and retired members and their dependents continued with no increase in co-payments. Newly employed inexperienced employees represented by the UMWA, hired after January 1, 2007 will not be eligible to receive retiree health care benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked.

Laws and Regulations

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

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

While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We post surety performance bonds or letters of credit pursuant to

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federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, often including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining and gas production for all domestic coal and gas producers. We also post performance bonds or letters of credit pursuant to state oil and gas laws and regulations to guarantee reclamation of gas well sites and plugging of gas wells. We endeavor to conduct our mining and gas operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining and gas operations occur from time to time. None of the violations to date, or the monetary penalties assessed have been material. CONSOL Energy made capital expenditures for environmental control facilities of approximately $50.4 million, $10.6 million and $17.6 million in the years ended December 31, 2009, 2008 and 2007, respectively. The capital expenditures for environmental control facilities increased in 2009 primarily due to starting construction of a water processing system at Buchanan Mine. CONSOL Energy expects to have capital expenditures of $39.0 million for 2010 for environmental control facilities.

Mine Health and Safety Laws

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

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

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

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

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

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

• the purchase of new fire resistant conveyor belting underground; and

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

Black Lung Legislation

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

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

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

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

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

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

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

1. the miner is totally disabled due to pneumoconiosis;

2. that the miners death was due to pneumoconiosis;

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

• be retroactive to claims filed or pending since 2005.

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

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

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Retiree Health Benefits Legislation

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

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

The Act requires some of our subsidiaries to make premium payments to the Combined Fund and to the 1992 Benefit Plan for the cost of our retirees and orphan retirees in the Combined Fund and the 1992 Benefit Plan. In addition, the NBCWA of 2007 requires our signatory subsidiaries to make specified payments to the 1993 Benefit Plan through 2011. The Tax Relief and Health Care Act of 2006 (the 2006 Act) provides additional federal funding for these orphan costs by authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land (AML) trust fund. The additional federal funding, depending upon its magnitude and the amount of orphan benefits payable, should cover the orphan premium payments due under the Combined Fund as well as, after a phase-in period, the orphan premium payments due under the 1992 Benefit Plan. The 1992 Benefit Plan has a phase-in period for the federal contributions. Federal contributions were 25% in 2008 and 50% in 2009. Federal contributions will be 75% in 2010 and 100% thereafter. In addition, federal contributions are also to be phased-in over these same periods with respect to the costs for those orphan retirees as of December 31, 2006 under the 1993 Benefit Plan. Under the 2006 Act, these general fund contributions to the Combined Fund, the 1992 Benefit Plan, the 1993 Benefit Plan and certain Abandoned Mine Land payments to the states and Indian tribes are collectively limited by an aggregate annual cap of $490 million. These federal contributions do not apply to our subsidiaries’ assigned retired miners, and therefore our subsidiaries will continue to make premium payments for our assigned retired miners who receive benefits from the Combined Fund, the 1992 Benefit Plan and for certain beneficiaries of the 1993 Benefit Plan. In addition, our subsidiaries remain responsible for making orphan premium payments to these plans to the extent that the federal contributions are not sufficient to cover the benefits.

Pension Protection Act

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

Environmental Laws

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

• the Surface Mining Control and Reclamation Act of 1977,

• the Clean Air Act,

• the Clean Water Act,

• the Toxic Substances Control Act,

• the Endangered Species Act,

• the Comprehensive Environmental Response, Compensation and Liability Act,

• the Emergency Planning and Community Right to Know Act, and

• the Resource Conservation and Recovery Act

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

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

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

Surface Mining Control and Reclamation Act

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

SMCRA permit provisions include requirements for coal exploration; baseline environmental data collection and analysis; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; refuse disposal plans; surface drainage control; mine drainage and mine discharge control and treatment; and site reclamation. The mining permit application process, whether state or federal, is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation and wildlife, and assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Detailed engineering plans are included for all surface facilities built as part of the mine, including roads, ponds, shafts and slopes, boreholes, portals, pipelines and power lines, excess spoil disposal areas and coal refuse disposal facilities. Also included in the permit application are documents defining corporate ownership and control, property ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required by the OSM Applicant Violator System. We also must list all public and privately-owned structures located within minimum defined distances near to or above our mines and mining facilities. Once a permit application is prepared and submitted to the regulatory agency, it goes through an administrative completeness review and a separate technical review. Public notice of the proposed permit application is given in a local newspaper followed by a public comment period before a permit can be issued. Some mining permits take over a year to prepare, depending on the size and complexity of the mine and can take six months to three years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance. The public has the right to comment on and otherwise participate in the permitting process, including through administrative appeals of permits and possibly further appeals in the courts. The mine operator must submit a bond or otherwise secure the performance of reclamation obligations, including, as deemed appropriate by the regulatory authority, a bond sufficient to cover the costs of long-term treatment of mine drainage discharges from closed facilities or ones from which a post-mining discharge is anticipated. The earliest a reclamation bond can be fully released is five years after reclamation has been completed, however, partial releases may be obtained as certain stages of reclamation are completed. All states impose on mine operators the responsibility for repairing or compensating for damage occurring on the surface as a result of mine subsidence, a possible consequence of longwall or other methods of underground mining, including an obligation to restore or replace domestic water supplies adversely affected by underground mining. All states also impose an obligation on surface mining operations to replace domestic, agricultural or industrial water supplies adversely affected by such operations. In addition, SMCRA imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine Reclamation Fund (AML Fund), which is used to restore unreclaimed and abandoned mine lands mined before 1977. The per ton fee is $0.315 for surface mined coal and $0.135 per ton for underground mined coal. From October 1, 2012 through September 30, 2021, the fees will be $0.28 per ton for surface mined coal and $0.12 per ton for underground mined coal.

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

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

Clean Air Act and Related Regulations

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

CONSOL Energy believes we have obtained all necessary permits under the Clean Air Act. These permits have various expiration dates through March 2015. CONSOL Energy monitors permits required by operations regularly and takes appropriate action to extend or obtain permits as needed.

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

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

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In 2005, the EPA finalized the Clean Air Mercury Rule (“CAMR”) which imposed caps on mercury emissions from coal-fired electric generating units. The first phase of the emission caps would have taken effect in 2010. In February 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR. EPA has indicated that it will develop emission limits for mercury for coal fired electric generating facilities under Section 112 of the Clean Air Act, which requires EPA to impose maximum achievable control technology limits. In October 2008, New York and the New England states submitted a petition to EPA under the Clean Water Act requesting EPA to convene a conference to address contributions of airborne mercury emissions that upwind states are alleged to be making to downwind water quality. This petition appears to be aimed at coal fired power plants. Various states have promulgated or are considering more stringent emission limits on mercury emissions from coal-fired electric generating units. Regulation of mercury emissions from coal-fired electric generating units could impact the market for coal.

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

The United States Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities and brought an administrative action against one government-owned utility for alleged violations of the Clean Air Act. These lawsuits could require the utilities to pay penalties, install pollution control equipment or undertake other emission reduction measures which could positively or negatively impact their demand for CONSOL Energy coal. One such suit was settled in October 2007, by the owner of sixteen coal fueled electric generating plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. Although the utility did not admit any violations of the Clean Air Act, it agreed to annual sulfur dioxide and nitrogen oxides emission limits for all of its plants and it agreed to install additional emission controls on two of its plants.

Also, numerous proposals have been made at the international, national, regional and state levels that are intended to limit or capture emissions of greenhouse gases, such as carbon dioxide, and several states have adopted measures intended to reduce greenhouse gas loading in the atmosphere. If comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States or individual states, it may adversely affect the use of and demand for fossil fuels, particularly coal, as an energy source for electricity generation. The U.S. Congress is considering climate change legislation that proposes to restrict greenhouse gas (GHG) emissions. President Obama has pledged to implement an economy-wide cap-and-trade program to reduce GHG emissions 80 percent by 2050 and pledged that he would cause the United States to be a world leader on GHG reduction and re-engage with the United Nations Framework Convention on Climate Change to develop a global GHG program. In 2007, the U.S. Supreme Court held in Massachusetts v. Environmental Protection Agency (EPA), that the EPA had authority to regulate GHGs under the Clean Air Act and a number of states have filed lawsuits seeking to force the EPA to adopt GHG regulations. In December 2009, the EPA made a determination that GHGs cause or contribute to air pollution and may reasonably be anticipated to endanger public health or welfare, which findings are prerequisites to EPA regulating GHGs under the Clean Air Act. Moreover, several states have already adopted, and other states are considering the adoption of, legislation or regulations to reduce emissions of greenhouse gases. Such regulation would significantly increase the cost of generation of electricity at coal fired facilities and could make competing forms of electricity generation more competitive.

Clean Water Act

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

Permits for discharges of fill material into streams in connection with mining operations are issued by the Army Corps of Engineers (the “COE”). The COE is empowered to issue “nationwide” permits for specific categories of filing activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404 of the Clean Water Act. Individual permits are required for activities determined to have more significant impacts to waters of the United States. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. Since 2003, environmental groups have pursued litigation primarily in West Virginia and Kentucky challenging the validity of Nationwide Permit 21 and various individual permits authorizing valley fills associated with surface coal mining operations (primarily mountain top removal operations). This litigation has resulted in delays in obtaining these permits and has increased permitting costs. The most recent major decision in this line of litigation is the opinion of the United States Court of

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Appeals for the Fourth Circuit in Ohio Valley Environmental Council v. Aracoma Coal Company, 556 F.3d 177 (2009) (Aracoma), issued on February 13, 2009. Aracoma appeared to be a major victory for the coal industry because the Court rejected all of the substantive challenges to the Section 404 permits involved in the case primarily by deferring to the expertise of the COE in review of the permit applications. The effect of the Aracoma decision was quickly nullified by several EPA initiatives. First, in early 2009, the EPA began to comment on Section 404 permit applications pending before the COE raising many of the same issues decided in favor of the coal industry in Aracoma. Many of the EPA’s comment letters were submitted long after the end of the EPA’s comment period based on what the EPA contended was “new” information on the impacts of valley fills on stream water quality immediately downstream of valley fills. However, the comment letters addressed many issues beyond the “new” information on alleged water quality impacts, such as, minimization of the size and number of valley fills, cumulative impacts of the operation on the watershed, and the types and extent of mitigation. These comment letters practically resulted in a moratorium on the issuance of Section 404 permits for valley fills for coal surface mines. A second initiative of the EPA is “enhanced” review of any permit for a coal mining activity that requires both a SMCRA permit and a Section 404 permit in the states of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia (designated as “Appalachian surface coal mining”). This initiative resulted in a joint Memorandum of Understanding (MOU) among the COE, the EPA and the Department of Interior (OSM). The “enhanced” review under the MOU has continued the delay in COE action on pending Section 404 permit applications. The EPA’s third initiative is to take a more active role in its review of NPDES permit applications for coal mining operations; especially in West Virginia where the EPA has decided to review all such NPDES permit applications. All of these initiatives have resulted in delays in the review and issuance of permits for surface coal mining applications. We anticipate that it will take longer to obtain permits and the costs of obtaining permits and compliance with permit conditions will increase significantly. So far, CONSOL Energy subsidiaries have been able to continue operating their existing mines. Also, in 2009 one subsidiary was able to obtain a Section 404 permit for a new surface mine in southern West Virginia. However, the new permit contains EPA mandated environmental protection conditions. Additionally, on January 4, 2010, the EPA published a notice in the Federal Register seeking public comment on the EPA’s enforcement and compliance priorities for fiscal years 2011 through 2013. The list of priorities includes energy/mining resource extraction (a new priority targeting mountain top removal mining).

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

Comprehensive Environmental Response, Compensation and Liability Act (Superfund)

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

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

Resource Conservation and Recovery Act

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

RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion wastes generated at electric utility and independent power producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA resulting in coal combustion wastes remaining exempt from hazardous waste regulation. However, the EPA determined that national non-hazardous waste regulations under RCRA are needed for coal combustion wastes disposed in surface impoundments and landfills and used as mine-fill, and the Office of Surface Mining is currently developing these regulations. The agency also concluded that beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. Most state hazardous waste laws also exempt coal combustion waste, and instead treat it as either a solid waste or a special waste. In response to the Tennessee Valley Authority coal ash spill in December 2008, the EPA initiated a fast-track

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regulatory process in which it is considering three possible regulatory scenarios for coal combustion wastes: regulation as a non-hazardous waste under Subtitle D of RCRA, regulation as a hazardous waste under Subtitle C, or a hybrid Subtitle C/D approach. Industry and state regulatory agencies are trying to convince the EPA that the states are adequately regulating handling and disposal of coal combustion wastes. The loss of the hazardous waste exemption for coal combustion waste, or the adoption of new regulations for disposing of coal combustion waste which impose significant additional costs, could adversely affect the demand for coal for electricity generation.

Federal Coal Leasing Amendments Act

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

Endangered Species Act

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

Federal Regulation of the Sale and Transportation of Gas

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

Regulations and orders set forth by the Federal Energy Regulatory Commission also impact our gas business to a certain degree. Although the Federal Energy Regulatory Commission does not directly regulate our gas production activities, the Federal Energy Regulatory Commission has stated that it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the Federal Energy Regulatory Commission continues to review its transportation regulations, including whether to allocate all short-term capacity on the basis of competitive auctions and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. Additional Federal Energy Regulatory Commission orders have been adopted based on this review with the goal of increasing competition for natural gas markets and transportation.

The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. In addition, the Federal Energy Regulatory Commission’s approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to Federal Energy Regulatory Commission regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future.

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

Additional proposals and proceedings that might affect the gas industry may be pending before Congress, the Federal Energy Regulatory Commission, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that

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the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of CONSOL Energy or its subsidiaries. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

State Regulation of Gas Operations

Our operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the disposal of fluids used in connection with operations, and gas operations producing coalbed methane in relation to active mining. Our operations are also subject to various conservation laws and regulations. These include regulations that affect the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of gas properties. In addition, state conservation laws establish maximum rates of production from gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. A number of states have either enacted new laws or may be considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. Our gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although we do not believe that they would be affected by such regulation any differently than other natural gas producers or gatherers. However, these regulatory burdens may affect profitability, and we are unable to predict the future cost or impact of complying with such regulations.

Ownership of Mineral Rights

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

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

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

Pennsylvania

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

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Virginia

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

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

West Virginia

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

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

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

Other States

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

Available Information

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

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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).

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

General

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

Steel plant capacity utilization rates in the U.S. and globally continued to improve compared to 2008. Domestic steel mills were using approximately 65% of their capacity, while Asian steel mills currently are using about 82% of their capacity. Chinese steel demand was again driving world demand and pricing for coking coal. Through its arrangement with Xcoal, CONSOL Energy expects to increase its sales to Asian mills throughout 2010.

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

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

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

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

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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 year-to-year comparison.

The coal segment includes steam coal, low volatile metallurgical coal and other coal. The steam coal aggregated segment includes: Bailey, Blacksville #2, Buchanan steam sales, Emery, Enlow Fork, Fola Complex, Jones Fork Complex, Loveridge, McElroy, Miller Creek Complex, Mine 84, Robinson Run and Shoemaker. The aggregate low volatile metallurgical coal segment includes the Buchanan metallurgical sales and the Amonate Complex. The other coal segment includes purchased coal activities, closed and idle mine costs and miscellaneous transactions that are directly related to the coal segment.

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 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.

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

The Total Coal segment contributed $558 million to earnings before income tax for the year ended December 31, 2009 compared to $363 million for the year ended December 31, 2008.

	Year Ended December 31, 2009									Difference to Year Ended  December 31, 2008
	Steam Coal		Low Vol Met Coal		Other Coal			Total Coal		Steam 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		—		—		89			89		—			—			(51	)		(51	)
Total Revenue and Other Income		3,122		249		277			3,648		399			(92	)		(198	)		109
Costs and Expenses:
Total operating costs		1,740		116		299			2,155		(25	)		(21	)		19			(27	)
Total provisions		180		15		28			223		(5	)		—			(18	)		(23	)
Total administrative & other costs		144		11		99			254		(2	)		(3	)		27			22
Depreciation, depletion and amortization		258		13		38			309		—			(1	)		11			10
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 Before Income Taxes	$	800	$	94	$	(336	)	$	558	$	431		$	(67	)	$	(169	)	$	195

STEAM COAL SEGMENT

The steam coal segment contributed $800 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			Percentage 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	%

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 the current period due to delivery deferments of Central and Northern Appalachian coals. Coal consumption by the electric power sector continued to decline during the year.

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Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income 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.

	2009		2008		Variance			Percentage Change
Produced Steam Tons Sold (in millions)		55.1		61.4		(6.3	)	(10.3	)%
Average Operating Cost Per Steam Ton Sold	$	31.58	$	28.70	$	2.88		10.0	%

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 the 2009 period 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-union mines. These contracts call for specified hourly wage increases in each year of the contract. The average increase in unit cost for labor was also impacted by lower sales volumes due to the economic environment as discussed above.

• 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 the prior period 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.

	2009		2008		Variance			Percentage Change
Produced Steam Tons Sold (in millions)		55.1		61.4		(6.3	)	(10.3	)%
Average Provision Costs Per Steam Ton Sold	$	3.27	$	3.01	$	0.26		8.6	%

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 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.

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	2009		2008		Variance			Percentage Change
Produced Steam Tons Sold (in millions)		55.1		61.4		(6.3	)	(10.3	)%
Average Selling, Administrative and Other Costs Per Steam Ton Sold	$	2.60	$	2.38	$	0.22		9.2	%

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.

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, none of which are individually material.

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 above.

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.

	2009		2008		Variance			Percentage Change
Produced Steam Tons Sold (in millions)		55.1		61.4		(6.3	)	(10.3	)%
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold	$	4.68	$	4.20	$	0.48		11.4	%

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LOW VOL METALLURGICAL COAL SEGMENT

The low vol 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 vol 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 vol metallurgical coal sold.

	2009		2008		Variance			Percentage Change
Produced Low Vol Metallurgical Tons Sold (in millions)		2.3		2.9		(0.6	)	(20.7	)%
Average Sales Price Per Low Vol Metallurgical Ton Sold	$	107.71	$	117.48	$	(9.77	)	(8.3	)%

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

Total costs for the low vol 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 vol metallurgical coal segment in the 2009 period, as discussed above. The impairments in unit costs are 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.

	2009		2008		Variance			Percentage Change
Produced Low Vol Metallurgical Tons Sold (in millions)		2.3		2.9		(0.6	)	(20.7	)%
Average Operating Cost Per Low Vol Met Ton Sold	$	50.36	$	47.17	$	3.19		6.8	%
Average Provision 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	$	5.45	$	4.75	$	0.70		14.7	%

OTHER COAL SEGMENT

The Other Coal segment negatively impacted earnings before tax by $336 million for the year ended December 31, 2009 compared to a negative $167 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 based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight revenue has decreased $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 the cost to the customer.

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Miscellaneous other income was $89 million for the year ended December 31, 2009 compared to $140 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 the 2008 period.

Other coal segment total cost was $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 the cost to the customer.

• 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.

• 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.

• 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.

• 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

36

idled and operating, throughout both periods which resulted in higher idled mine costs in 2009 period. 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 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.

• Other coal segment costs increased $17 million 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.

• 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.

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

The Total Gas segment contributed $262 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

	Year Ended December 31, 2009													Difference to Year Ended  December 31, 2008
	CBM		Conventional			Marcellus		Other Gas			Total Gas			CBM			Conventional			Marcellus		Other Gas			Total Gas
Sales:
Produced	$	593	$	9		$	21	$	4		$	627		$	(86	)	$	9		$	21	$	4		$	(52	)
Related Party		2		—			—		—			2			—			—			—		—			—
Total Outside Sales		595		9			21		4			629			(86	)		9			21		4			(52	)
Gas Royalty Interest		—		—			—		41			41			—			—			—		(38	)		(38	)
Purchased Gas		—		—			—		7			7			—			—			—		(2	)		(2	)
Other Income		—		—			—		5			5			—			—			—		(8	)		(8	)
Total Revenue and Other Income		595		9			21		57			682			(86	)		9			21		(44	)		(100	)
Lifting		50		4			1		—			55			(18	)		4			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		—		—			—		33			33			—			—			—		12			12
Interest Expense		—		—			—		8			8			—			—			—		—			—
Total Cost		294		10			17		100			421			14			10			17		(16	)		25
Earnings Before Noncontrolling Interest and Income Tax		301		(1	)		4		(43	)		261			(100	)		(1	)		4		(28	)		(125	)
Noncontrolling Interest		—		—			—		(1	)		(1	)		—			—			—		(1	)		(1	)
Earnings Before Income Tax	$	301	$	(1	)	$	4	$	(42	)	$	262		$	(100	)	$	(1	)	$	4	$	(27	)	$	(124	)

COALBED METHANE (CBM) GAS SEGMENT:

The CBM segment contributed $301 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 $86 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			Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		86.5		75.7		10.8		14.3	%
Average CBM Sales Price per thousand cubic feet sold	$	6.88	$	9.00	$	(2.12	)	(23.6	)%

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 CNX Gas. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 51.6 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2009 at an average price of $8.76 per thousand cubic feet. In the year ended December 31, 2008, these financial hedges represented approximately 43.4 billion cubic feet at an average price of $9.25 per thousand cubic feet.

CBM lifting costs were $50 million for the year ended December 31, 2009 compared to $68 million for the year ended December 31, 2008.

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	2009		2008		Variance			Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		86.5		75.7		10.8		14.3	%
Average CBM lifting costs per thousand cubic feet	$	0.57	$	0.89	$	(0.32	)	(36.0	)%

Average lifting costs per unit decreased in 2009 as a result of the following:

• Severance taxes have decreased $0.20 per thousand cubic feet primarily due to the reduction in average sales prices in the year ended December 31, 2009. The severance tax decrease also includes a reduction of $0.05 per thousand cubic feet attributable to a revised estimate of a pending litigation settlement.

• Well service costs have also decreased by $0.07 per thousand cubic feet due to lower contract service rig hours needed as a result of less pump maintenance being required in the year ended December 31, 2009.

• Other costs have decreased $0.15 per thousand cubic feet primarily due to the impact of additional volumes of gas sold during 2009. Dollars spent remained consistent in the year-to-year comparisons, therefore additional volumes decreased the unit costs.

• These decreases in unit costs were offset, in part, by a $0.10 per thousand cubic feet increase related to idling various drilling rigs throughout the company. Some of CNX Gas’ drilling contracts require minimum payments be made to the contracting party when drilling rigs are not being used. The CNX Gas drilling program has been slowed down pending a change in the economic environment. These charges resulted in an increase to costs.

The increase of $4 million in gathering and compression costs 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.

	2009		2008		Variance			Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		86.5		75.7		10.8		14.3	%
Average CBM gathering and compression costs per thousand cubic feet sold	$	1.02	$	1.11	$	(0.09	)	(8.1	)%

Average gathering and compression unit costs were $0.09 per thousand cubic feet lower in the period-to-period comparison. Improvements in the average unit costs were attributable to the following:

• Gob collection charges were $0.04 per thousand cubic feet lower. Lower gob collection charges per unit were primarily due to the Buchanan longwall being idled throughout a portion of the 2009 period.

• Compression expenses decreased $0.03 per thousand cubic feet 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 for existing needs.

• Other costs have decreased $0.14 per thousand cubic feet primarily due to the impact of additional volumes of gas sold during 2009. Dollars spent remained consistent in the year-to-year comparison, therefore additional volumes decreased the unit cost.

These decreases in unit costs were offset by the following:

• Firm transportation costs increased $0.08 per thousand cubic feet primarily due to acquiring additional capacity in the Southwest Pennsylvania operation after December 31, 2008.

• Power and fuel costs increased $0.04 per thousand cubic feet due to a power rate increase which occurred after December 31, 2008. Also, the increase was due to additional compressors being placed in service after December 31, 2008 along the existing gathering system in the 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.

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	2009		2008		Variance			Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		86.5		75.7		10.8		14.3	%
Average CBM general and administrative costs per thousand cubic feet sold	$	0.71	$	0.78	$	(0.07	)	(9.0	)%

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 the 2009 period.

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.

	2009		2008		Variance		Percentage Change
Produced gas CBM sales volumes (in billion cubic feet)		86.5		75.7		10.8	14.3	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	$	1.09	$	0.92	$	0.17	18.5	%

Production related depreciation, depletion and amortization related to the CBM segment was $72 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 $22 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 $3 million in 2009 due to assets placed in service after December 31, 2008.

CONVENTIONAL GAS SEGMENT:

The Conventional segment contributed a negative $1 million to the total company earnings before income tax 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		Percentage 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	$	5.41	$	—	$	5.41	100.0	%
Average Conventional lifting costs per thousand cubic feet sold	$	2.76	$	—	$	2.76	100.0	%
Average Conventional gathering and compression costs per thousand cubic feet sold	$	0.59	$	—	$	0.59	100.0	%
Average Conventional general and 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	%

MARCELLUS GAS 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.

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	2009		2008		Variance		Percentage Change
Produced gas Marcellus sales volumes (in billion cubic feet)		4.9		—		4.9	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 and compression costs per thousand cubic feet sold	$	1.12	$	—	$	1.12	100.0	%
Average Marcellus general and 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	%

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 the 2009 period. Total costs related to these other sales were $4 million in the 2009 period. 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			Percentage Change
Royalty Interest gas 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			Percentage Change
Purchased Gas sales volumes (in billion cubic feet)		1.6		1.0		0.6		60.0	%
Average Sales Price per thousand cubic feet 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.

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	2009		2008		Variance			Percentage Change
Royalty Interest gas sales volumes (in billion cubic feet)		9.8		8.5		1.3		15.3	%
Average Cost Price per thousand cubic feet	$	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			Percentage Change
Purchased Gas volumes (in billion cubic feet)		1.7		1.0		0.7		70.0	%
Average Cost Price per thousand cubic feet	$	3.75	$	8.13	$	(4.38	)	(53.9	)%

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

	2009		2008		Dollar Variance		Percentage Change
Dry hole and other costs	$	9	$	1	$	8	800.0	%
Exploration expense		8		3		5	166.7	%
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		Dollar Variance			Percentage Change
Short-term incentive compensation	$	16	$	8	$	8		100.0	%
Contract settlement		3		—		3		100.0	%
Stock-based compensation		11		12		(1	)	(8.3	)%
Miscellaneous		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.

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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 the 2008 period.

Stock-based compensation expense decreased $1 million in the year-to-year comparison. The improvement was related to the CNX Gas long-term incentive compensation plan being converted to CONSOL Energy restricted stock units in 2009. The year ended December 31, 2009 contains $3 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

Noncontrolling interest represents 100% of the earnings impact of a third party which has been determined to be a variable interest entity, in which CNX Gas holds no ownership interest, but is the primary beneficiary. CNX Gas 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 CNX Gas. CNX Gas consolidates the entity and reflects 100% of the impact as noncontrolling interest. The consolidation does not significantly impact any amounts reflected in the CNX Gas income statement. The variance in the noncontrolling amounts reflects the third party’s variance in earnings in the year-to-year comparison.

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

	For the Years Ended December 31,
	2009			2008			Variance			Percentage Change
Sales-Outside	$	271		$	316		$	(45	)	(14.2	)%
Other Income		20			16			4		25.0	%
Total Revenue		291			332			(41	)	(12.3	)%
Cost of Goods Sold and Other Charges		291			324			(33	)	(10.2	)%
Depreciation, Depletion & Amortization		19			20			(1	)	(5.0	)%
Taxes Other Than Income Tax		13			11			2		18.2	%
Total Costs		323			355			(32	)	(9.0	)%
Earnings Before Income Tax		(32	)		(23	)		(9	)	(39.1	)%
Income Tax		221			240			(19	)	(7.9	)%
Net Income	$	(253	)	$	(263	)	$	10		3.8	%

The Other segment includes activity from sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment negatively contributed $32 million to total company earnings before income tax for the year ended December 31, 2009 compared to a negative contribution of $23 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 $191 million for the years ended December 31, 2009 and 2008.

43

Transportation operation:

Total revenue related to the transportation operations were $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 $75 million for the year ended December 31, 2009 compared to $101 million for the year ended December 31, 2008. The decrease of $26 million was related to lower tonnage moved and lower employee counts throughout the year ended December 31, 2009.

Miscellaneous Other:

Other income was $11 million for the year ended December 31, 2009 compared to $2 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.

Other corporate costs in the other segment include interest cost and various other miscellaneous corporate charges. Total other costs were $57 million for the year ended December 31, 2009 compared to $63 million in the year ended December 31, 2008. Other corporate costs decreased due to the following:

• 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. Due mainly to the downturn in the economy, it is not probable that the company can repay these loans, or that the company will complete a public offering. Therefore, the asset values have been written down.

• Other costs decreased $8 million due to various transactions that occurred throughout both periods, none of which were individually material.

• Various other corporate items increased $8 million primarily due to expenses recognized in conjunction with the 2009 cease use of the previous headquarters. The increase was also attributable to various transactions that occurred throughout both periods, none of where were individually material.

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 Item 8, Consolidated Financial Statements of Form 8-K.

	2009			2008			Variance			Percentage 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	)%

44

Results of Operations

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

Net Income Attributable to CONSOL Energy Shareholders

CONSOL Energy reported net income attributable to CONSOL Energy shareholders of $442 million, or $2.40 per diluted share, for the year ended December 31, 2008. Net income attributable to CONSOL Energy shareholders was $268 million, or $1.45 per diluted share for the year ended December 31, 2007. See below for a detailed explanation by segment of the variance incurred in the year-to-year comparison.

The coal segment includes steam coal, low volatile metallurgical coal and other coal. The steam coal aggregated segment includes: Bailey, Blacksville #2, Buchanan steam sales, Emery, Enlow Fork, Fola Complex, Jones Fork Complex, Loveridge, McElroy, Miller Creek Complex, Mine 84, Robinson Run and Shoemaker. The aggregate low volatile metallurgical coal segment includes the Buchanan metallurgical sales and the Amonate Complex.

The gas segment includes coalbed methane (CBM), conventional, Marcellus and other gas. For the years ended December 31, 2008 and 2007, 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 meaningful comparison of these operations will not be discussed.

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.

45

TOTAL COAL SEGMENT ANALYSIS for the year ended December 31, 2008 compared to December 31, 2007:

The Total Coal segment contributed $363 million to earnings before income tax for the year ended December 31, 2008 compared to $233 million for the year ended December 31, 2007.

													Difference to
	Year Ended December 31, 2008									Year Ended December 31, 2007
			Low										Low
			Vol										Vol
	Steam		Met		Other			Total		Steam			Met		Other			Total
	Coal		Coal		Coal			Coal		Coal			Coal		Coal			Coal
Sales:
Produced Coal	$	2,723	$	341	$	—		$	3,064	$	296		$	126	$	—		$	422
Purchased Coal		—		—		118			118		—			—		81			81
Total Outside Sales		2,723		341		118			3,182		296			126		81			503
Freight Revenue		—		—		217			217		—			—		30			30
Other Income		—		—		140			140		—			—		(33	)		(33	)
Total Revenue and Other Income		2,723		341		475			3,539		296			126		78			500
Costs and Expenses:
Total operating costs		1,765		137		280			2,182		288			19		(48	)		259
Total provisions		185		15		46			246		23			5		(20	)		8
Total administrative & other costs		146		14		72			232		24			6		(4	)		26
Depreciation, depletion and amortization		258		14		27			299		40			5		2			47
Total Costs and Expenses		2,354		180		425			2,959		375			35		(70	)		340
Freight Expense		—		—		217			217		—			—		30			30
Total Cost		2,354		180		642			3,176		375			35		(40	)		370
Earnings Before Income Taxes	$	369	$	161	$	(167	)	$	363	$	(79	)	$	91	$	118		$	130

STEAM COAL SEGMENT

The steam coal segment contributed $369 million to total company earnings before income tax for the year ended December 31, 2008 compared to $448 million for the year ended December 31, 2007.

Steam coal revenue was $2,723 million for the year ended December 31, 2008 compared to $2,427 million for the year ended December 31, 2007. The increase of $296 million was primarily attributable to a higher average price per ton sold.

							Percentage
	2008		2007		Variance		Change
Produced Steam Tons Sold (in millions)		61.4		61.4		—	—
Average Sales Price Per Steam Ton Sold	$	44.31	$	39.53	$	4.78	12.1	%

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.

46

Operating costs are made up of labor, supplies, maintenance, subsidence, taxes other than income 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 $1,765 million for the year ended December 31, 2008 compared to $1,477 million for the year ended December 31, 2007.

							Percentage
	2008		2007		Variance		Change
Produced Steam Tons Sold (in millions)		61.4		61.4		—	—
Average Operating Cost Per Steam Ton Sold	$	28.70	$	24.05	$	4.65	19.3	%

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

• Supply and maintenance costs have increased due to the following items:

• Supply costs increased in the year-to-year comparison due to the installation of higher grade seals and due to a higher number of seals being built in the 2008 period. The Mine Health and Safety Administration now requires higher strength seals to be constructed in order to isolate old, abandoned areas of previously sealed areas of the mine. The increase in strength of seals was required to better protect the active sections of the underground mines from explosions, fires, or other situations that may occur within the sealed areas.

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

• Gas well plugging/drilling costs related to the mining process have increased in 2008 compared to 2007. Gas well plugging expenses are related to plugging abandoned gas wells which CONSOL Energy does not own that are in front of the underground mining process. These wells have to be plugged in accordance with current safety regulations in order to mine through. CONSOL Energy has plugged more wells in 2008 than in 2007, which has contributed to increased supply costs.

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

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

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

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

• Production taxes per steam ton sold increased due to higher severance tax and reclamation fee taxes attributable to the increase in average sales.

• Combined Fund costs increased due to the 2007 settlement with the Fund. In March 2007, CONSOL Energy entered into a settlement agreement with the Combined Fund that resolved all previous issues relating to the calculation of the payments. The total company income, including interest, as a result of this settlement was approximately $33.4 million, of which approximately $28.1 million impacted total company costs.

• United Mine Workers of America (UMWA) health and retirement plan expenses increased due to additional contributions required to be made into employee benefit funds in 2008 compared to 2007 as a result of the five-year labor agreement with the UMWA that commenced January 1, 2007. The contribution increase over 2007 was $1.27 per UMWA hour worked.

47

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

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 $185 million for the year ended December 31, 2008 compared to $162 million for the year ended December 31, 2007.

							Percentage
	2008		2007		Variance		Change
Produced Steam Tons Sold (in millions)		61.4		61.4		—	—
Average Provision Costs Per Steam Ton Sold	$	3.01	$	2.63	$	0.38	14.4	%

Total CONSOL Energy expenses related to our actuarial liabilities were $243 million for the year ended December 31, 2008 compared to $223 for the year ended December 31, 2007. The increase of $20 million was primarily attributable to changes in discount rates used at the measurement dates and changes in assumptions which affect the amount amortized into earnings.

Provision costs per unit increased in the year-to-year comparison due primarily to higher charges incurred by the total company as discussed above.

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, 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 $146 million for the year ended December 31, 2008 compared to $122 million for the year ended December 31, 2007.

							Percentage
	2008		2007		Variance		Change
Produced Steam Tons Sold (in millions)		61.4		61.4		—	—
Average Selling, Administrative and Other Costs Per Steam Ton Sold	$	2.38	$	1.99	$	0.39	19.6	%

Average selling, general and administrative costs per unit have increased in the year-to-year comparison due to the higher total company expense as discussed below.

Total company selling, general and administrative costs were $125 million for the year ended December 31, 2008 compared to $109 million for the year ended December 31, 2007. The $16 million increase was due to the following items.

• Wages, salaries and related benefits increased $9 million in the year-to-year comparison due to additional administrative staffing at various subsidiaries and various other increases in support staff throughout CONSOL Energy.

• Association assessments have increased $5 million in the year-to-year comparison due primarily to CONSOL Energy’s participation in an industry organization which has launched a program related to the promotion of coal as an energy solution. CONSOL Energy did not participate in this organization in 2007. Also, CONSOL Energy participates in various associations and contributes to various charities in an effort to support the professions and the communities in which we do business. The level of funding made to these organizations varies from year-to-year.

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

• Other selling, general and administrative costs increased $2 million due to various transactions none of which are individually material.

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

Depreciation, depletion and amortization was $258 million for the year ended December 31, 2008 compared to $218 million for the year ended December 31, 2007. Average depreciation, depletion and amortization unit costs increased $0.64 per ton primarily due to additional expense related to the assets purchased in the July 2007 acquisition of AMVEST. The increase was also attributable to assets placed in service after December 31, 2007.

							Percentage
	2008		2007		Variance		Change
Produced Steam Tons Sold (in millions)		61.4		61.4		—	—
Average Depreciation, Depletion and Amortization Costs Per Steam Ton Sold	$	4.20	$	3.56	$	0.64	18.0	%

LOW VOL METALLURGICAL COAL SEGMENT

The low vol metallurgical coal segment contributed $161 million to total company earnings before income tax for the year ended December 31, 2008 compared to $70 million for the year ended December 31, 2007.

Low vol metallurgical coal revenue was $341 million for the year ended December 31, 2008 compared to $215 million for the year ended December 31, 2007. The increase of $126 million was due to the higher average price per ton sold, offset, in part, by lower sales volumes of company produced low vol metallurgical coal due to production at the Buchanan mine being suspended after several roof falls in previously mined areas damaged some of the ventilation controls inside the mine in July 2007. The mine resumed longwall production on March 17, 2008.

								Percentage
	2008		2007		Variance			Change
Produced Low Vol Metallurgical Tons Sold (in millions)		2.9		3.4		(0.5	)	(14.7	)%
Average Sales Price Per Low Vol Metallurgical Ton Sold	$	117.48	$	63.06	$	54.42		86.3	%

The increase in average sales price for low vol metallurgical coal was the result of global coal fundamentals being more favorable in the current year. Concerns regarding the adequacy of global supplies of coal have strengthened both the international and domestic coal prices.

Total costs for the low vol metallurgical coal segment were $180 million for the year ended December 31, 2008 compared to $145 million for the year ended December 31, 2007. A meaningful comparison of unit costs cannot be made because of the low volume of coal produced and sold from the low vol metallurgical coal segment in the 2008 period as discussed above. The 2008 unit costs are not representative of the operating mine due to fixed costs being spread over significantly fewer tons.

								Percentage
	2008		2007		Variance			Change
Produced Low Vol Metallurgical Tons Sold (in millions)		2.9		3.4		(0.5	)	(14.7	)%
Average Operating Cost Per Low Vol Met Ton Sold	$	47.17	$	34.72	$	12.45		35.9	%
Average Provision Per Low Vol Met Ton Sold	$	5.31	$	2.91	$	2.40		82.5	%
Average Selling, Administrative and Other Costs Per Low Vol Met Ton Sold	$	4.71	$	2.35	$	2.36		100.4	%
Average Depreciation, Depletion and Amortization Costs Per Low Vol Met Ton Sold	$	4.75	$	2.63	$	2.12		80.6	%

49

OTHER COAL SEGMENT

The Other Coal segment negatively impacted earnings before tax by $167 million for the year ended December 31, 2008 compared to a negative $285 for the year ended December 31, 2007. 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 $118 million for the year ended December 31, 2008 and $37 million in the year ended December 31, 2007. The increase of $81 million in purchased coal revenue was primarily due to an increase in demand in the year-to-year comparisons.

Freight revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight revenue has increased $30 million in 2008 primarily due to freight associated with AMVEST, which was acquired July 31, 2007. Freight Revenue has also increased due to higher freight rates being charged for exported tons. These increases in freight revenue were offset, in part, by lower export tons shipped in 2008 compared to 2007. There were 7.0 million tons and 7.6 million tons of coal exported by CONSOL Energy in 2008 and 2007, respectively.

Miscellaneous other income was $140 million for the year ended December 31, 2008 compared to $173 million for the year ended December 31, 2007. The $33 million decrease was made up of the following items:

• Gain on sale of assets decreased $82 million in the year-to-year comparison primarily due to the following transactions:

• In June 2007, CONSOL Energy exchanged certain coal assets in Northern Appalachia to Peabody Energy for coalbed methane and gas rights, which resulted in a pretax gain of $50 million.

• In June 2007, CONSOL Energy sold the rights to certain western Kentucky coal in the Illinois Basin to Alliance Resource Partners, L.P. for $53 million. This transaction resulted in a pretax gain of approximately $50 million.

• In February 2008, CONSOL Energy completed the sale of the Mill Creek Mining Complex, which resulted in a pretax gain of approximately $5 million.

• In September 2008, CONSOL Energy sold an idled facility which included the transfer of the mine closing liabilities to the buyer. This transaction resulted in a pretax gain of approximately $8 million.

• Other gain on sales of assets increased $5 million in the year-to-year comparison due to various transactions that occurred throughout both years, none of which were individually material.

• A litigation settlement with a coal customer in 2007 resulted in $5 million of income. There were no corresponding transactions in 2008.

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

• Royalty Income increased $6 million in the year-to-year comparison due to production of CONSOL Energy coal by a third-party commencing in August 2007. Royalties have also increased due to the higher sales price of coal sold throughout 2008 compared to 2007.

• In 2008, CONSOL Energy received $50 million as final settlement of insurance claims related to the July 2007 Buchanan Mine incident, which idled the mine from July 2007 to mid-March 2008. The $50 million represents business interruption coverage which was recognized in other income; the coal segment recognized $42 million and the gas segment recognized $8 million. CONSOL Energy had received $10 million of business interruption proceeds related to this incident in 2007; the coal segment recognized $8 million and the gas segment recognized $2 million. In 2007, $15 million was also received from the insurance carrier for reimbursement of fire brigade costs. This was recognized as a reduction of cost of goods sold and other charges. The final settlement brought the total amount recovered from insurance carriers to $75 million, the maximum allowed per covered event. No additional amounts related to Buchanan roof caving event will be recovered. All proceeds from this insurance claim have been received.

50

• Other miscellaneous income increased $8 million in the year-to-year comparison due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Other coal segment total cost was $642 million for the year ended December 31, 2008 compared to $682 million for the year ended December 31, 2007. The decrease of $40 million was due to the following items:

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

• Closed and idle mine costs decreased approximately $34 million in 2008 compared to 2007. The decrease was primarily due to $20 million of reduced costs at Shoemaker Mine. Shoemaker resumed longwall production in May 2008, but was idled throughout all of 2007. The decrease was also related to updated engineering surveys related to mine closing, perpetual care water treatment and reclamation liabilities for closed and idled locations resulting in $23 million of expense in 2008 compared to $33 million of expense in 2007. The higher 2007 survey adjustments related primarily to perpetual water treatment changes in estimates of water flows and increased hydrated lime costs. Closed and idle costs also decreased $4 million due to various other changes which occurred throughout both periods, none of which were individually significant.

• Purchased coal costs increased $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, coal purchased from third parties and sold directly to our customers and costs related to processing third-party coal in our preparation plants. The increase was primarily due to higher volumes purchased in the year-to-year comparison.

• Freight expense increased $30 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 increased in 2008 due primarily to freight associated with AMVEST, which was acquired on July 31, 2007. Freight has also increased due to higher freight rates being charged for exported tons. These increases in freight expense were offset, in part, by lower export tons shipped in 2008 compared to 2007. There were 7.0 million tons and 7.6 million tons of coal exported by CONSOL Energy in 2008 and 2007.

• In July 2007, production at Buchanan Mine was suspended after several roof falls in previously mined areas damaged some of the ventilation controls inside the mine, requiring a general evacuation of the mine. In 2008, we have incurred approximately $21 million of costs related to the Buchanan Mine event compared to $104 million in the prior year. The 2007 expense figure is net of $15 million related to insurance proceeds received as reimbursement for costs incurred under the policy. The mine resumed longwall production on March 17, 2008.

• The year ended December 31, 2008 includes adjustments related to CONSOL Energy agreements to buy out coal sales contracts with several customers in order to release tons committed under lower priced contracts for sale to other customers at higher prices. The costs for these transactions was $19 million in 2008. No such agreements were made in 2007.

• 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.

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

• Other miscellaneous costs increased $12 million in the year-to-year comparison due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

52

TOTAL GAS SEGMENT ANALYSIS for the year ended December 31, 2008 compared to the year ended December 31, 2007:

The Total Gas segment contributed $386 million to earnings before income tax for the year ended December 31, 2008 compared to $215 million for the year ended December 31, 2007. For the years ended December 31, 2008 and 2007, 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 have not been presented. All comparisons and explanations are related to the CBM and Other gas segment.

																	Difference to
	For the Year Ended December 31, 2008											Year Ended December 31, 2007
							Other			Total									Other			Total
	CBM		Conventional		Marcellus		Gas			Gas		CBM			Conventional		Marcellus		Gas			Gas
Sales:
Produced	$	679	$	—	$	—	$	—		$	679	$	274		$	—	$	—	$	—		$	274
Related Party		2		—		—		—			2		(3	)		—		—		—			(3	)
Total Outside Sales		681		—		—		—			681		271			—		—		—			271
Gas Royalty Interest		—		—		—		79			79		—			—		—		32			32
Purchased Gas		—		—		—		9			9		—			—		—		1			1
Other Income		—		—		—		13			13		—			—		—		5			5
Total Revenue and Other Income		681		—		—		101			782		271			—		—		38			309
Lifting		68		—		—		—			68		29			—		—		—			29
Gathering		84		—		—		—			84		22			—		—		—			22
General & Administration		58		—		—		—			58		16			—		—		—			16
Depreciation, Depletion and Amortization		70		—		—		—			70		21			—		—		—			21
Gas Royalty Interest		—		—		—		75			75		—			—		—		35			35
Purchased Gas		—		—		—		8			8		—			—		—		1			1
Exploration and Other Costs		—		—		—		4			4		—			—		—		4			4
Other Corporate		—		—		—		21			21		—			—		—		8			8
Interest Expense		—		—		—		8			8		—			—		—		2			2
Total Cost		280		—		—		116			396		88			—		—		50			138
Earnings Before Noncontrolling Interest and Income Tax		401		—		—		(15	)		386		183			—		—		(12	)		171
Noncontrolling Interest		—		—		—		—			—		—			—		—		—			—
Earnings Before Income Tax	$	401	$	—	$	—	$	(15	)	$	386	$	183		$	—	$	—	$	(12	)	$	171

COALBED METHANE (CBM) GAS SEGMENT:

The CBM segment contributed $401 million to the total company earnings before income tax for the year ended December 31, 2008 compared to $218 million for the year ended December 31, 2007. The increase is due to the following items.

CBM sales revenues increased $271 million in the year-to-year comparison. The increase in outside sales was primarily due to higher average sales prices received and higher volumes of gas sold.

							Percentage
	2008		2007		Variance		Change
Produced gas CBM sales volumes (in billion cubic feet)		75.7		57.1		18.6	32.6	%
Average CBM Sales Price per thousand cubic feet sold	$	9.00	$	7.19	$	1.81	25.2	%

53

Sales volumes increased as a result of additional wells coming online from our on-going drilling program. Prior year sales volumes were impacted by the deferral of production related to the Buchanan mine issue. The increase in average sales price is the result of the general market price increases in the year-to-year comparison. CNX Gas also periodically enters into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. These financial hedges represented approximately 43.4 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2008 at an average price of $9.25 per thousand cubic feet. In the year ended December 31, 2007, these financial hedges represented approximately 18.4 billion cubic feet at an average price of $8.01 per thousand cubic feet.

CBM lifting costs were $68 million for the year ended December 31, 2008 compared to $39 million for the year ended December 31, 2007.

							Percentage
	2008		2007		Variance		Change
Produced gas CBM sales volumes (in billion cubic feet)		75.7		57.1		18.6	32.6	%
Average CBM lifting costs per thousand cubic feet sold	$	0.89	$	0.68	$	0.21	30.9	%

Average lifting costs per unit sold increased in 2008 as a result of the following items:

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

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

• Severance taxes per unit sold were $0.04 per thousand cubic feet higher in 2008. The increase in severance tax was attributable to the higher average sale prices for gas.

• Repairs and maintenance costs have increased $0.04 per thousand cubic feet due to higher material costs and higher contract labor costs.

• Fuel and chemical costs have increased $0.02 per thousand cubic feet due to higher costs of these commodities in the year-to-year comparison.

• Various other costs have also increased by $0.01 per thousand cubic feet for various items which occurred throughout both years, none of which were individually material.

CBM gathering costs were $84 million for the year ended December 31, 2008 compared to $62 million for the year ended December 31, 2007.

							Percentage
	2008		2007		Variance		Change
Produced gas CBM sales volumes (in billion cubic feet)		75.7		57.1		18.6	32.6	%
Average CBM gathering and compression costs per thousand cubic feet sold	$	1.11	$	1.08	$	0.03	2.8	%

The increase in average gathering and compression unit costs was attributable to the following items:

• Fuel and power increased $0.06 per thousand cubic feet due to additional compressors being placed in service in anticipation of higher production volumes in the future.

• Compression expenses increased $0.02 per thousand cubic feet due to the additional compressors discussed above.

These increases in average gathering and compression costs were offset, in part, by the following item:

• Repair and maintenance expense decreased $0.05 per thousand cubic feet. Dollars spent for maintenance have remained fairly consistent in the year-to-year comparison; therefore, additional volumes gathered and transported have lowered the related unit costs for these components.

54

General and administrative costs for the CBM gas segment were $58 million for the year ended December 31, 2008 compared to $42 million for the year ended December 31, 2007.

							Percentage
	2008		2007		Variance		Change
Produced gas CBM sales volumes (in billion cubic feet)		75.7		57.1		18.6	32.6	%
Average CBM general and administrative costs per thousand cubic feet sold	$	0.78	$	0.75	$	0.03	4.0	%

General and administrative expenses increased due to the following items:

• Employee wages, salaries and related expenses increased $0.06 per thousand cubic feet due to the additional staffing added as a result of the on-going growth of the gas segment.

• Various other costs have decreased $0.03 per thousand cubic feet primarily due to additional volumes. Dollars spent have remained fairly consistent; therefore, additional volumes have lowered the related unit costs for these components.

Depreciation, depletion and amortization costs were $70 million for the year ended December 31, 2008 compared to $49 million for the year ended December 31, 2007.

							Percentage
	2008		2007		Variance		Change
Produced gas CBM sales volumes (in billion cubic feet)		75.7		57.1		18.6	32.6	%
Average CBM depreciation, depletion and amortization costs per thousand cubic feet sold	$	0.92	$	0.86	$	0.06	7.0	%

Production related depreciation, depletion and amortization related to the CBM segment was $51 million for the year ended December 31, 2008 compared to $32 million for the year ended December 31, 2007. 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 $19 million for the year ended December 31, 2008 compared to $17 million for the year ended December 31, 2007. Gathering depreciation, depletion and amortization is recorded using the straight-line method and increased $2 million in 2008 due to assets placed in service after December 31, 2007.

OTHER GAS SEGMENT:

The Other gas segment includes activity not assigned to the CBM gas segment. This segment includes purchased gas activity, gas royalty interest activity, exploration and other costs, other corporate expenses, and miscellaneous operational activity.

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 $79 million for the year ended December 31, 2008 compared to $47 million for the year ended December 31, 2007. The increase in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties, contributed to the year-to-year change in both dollars and on a unit basis.

							Percentage
	2008		2007		Variance		Change
Royalty Interest gas sales volumes (in billion cubic feet)		8.5		7.2		1.3	18.1	%
Average Sales Price per thousand cubic feet sold	$	9.32	$	6.44	$	2.88	44.7	%

55

Purchased gas sales volumes represent volumes of gas we sold at market prices that were purchased from third-party producers. Purchased gas sales were $9 million for the year ended December 31, 2008 compared to $8 million for the year ended December 31, 2007. The increase was primarily due to the increase in market prices in the year-to-year comparison.

								Percentage
	2008		2007		Variance			Change
Purchased Gas sales volumes (in billion cubic feet)		1.0		1.1		(0.1	)	(9.1	)%
Average Sales Price per thousand cubic feet sold	$	8.76	$	7.19	$	1.57		21.8	%

Other income increased $5 million mainly 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 income of $8 million related to the settlement contributed to an increase of $6 million in the year-to-year comparison. Various other income items decreased $1 million, none of which were individually material.

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 $75 million for the year ended December 31, 2008 compared to $40 million for the year ended December 31, 2007. Increased volumes and the increase in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the year-to-year change.

							Percentage
	2008		2007		Variance		Change
Royalty Interest gas sales volumes (in billion cubic feet)		8.5		7.2		1.3	18.1	%
Average Cost Price per thousand cubic feet sold	$	8.69	$	5.52	$	3.17	57.4	%

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 $8 million for the year ended December 31, 2008 compared to $7 million for the year ended December 31, 2007. The higher average cost per thousand cubic feet is due to overall market price increases and contractual differences among customers in the year-to-year comparison.

								Percentage
	2008		2007		Variance			Change
Purchased Gas volumes (in billion cubic feet)		1.0		1.1		(0.1	)	(9.1	)%
Average Cost Price per thousand cubic feet sold	$	8.13	$	6.66	$	1.47		22.1	%

Exploration and Other Costs increased $4 million due to additional exploration costs incurred in 2008 compared to 2007. These additional costs are the results of the on-going ramp up of our exploration program. These costs have also increased due to the reversal of previously capitalized drilling costs related to unsuccessful wells. Capitalized costs for four unsuccessful wells were expensed in 2008. There were no unsuccessful wells in 2007. Under the successful efforts method of accounting, drilling costs are capitalized until it is determined that gas cannot be economically produced from the well.

Other corporate expenses have increased $8 million due to the following items:

					Dollar			Percentage
	2008		2007		Variance			Change
Stock-based compensation	$	12	$	5	$	7		140.0	%
Short-term incentive compensation		8		6		2		33.3	%
Miscellaneous		1		2		(1	)	(50.0	)%
Total Other Corporate Expenses	$	21	$	13	$	8		61.5	%

Stock-based compensation increased $7 million primarily due to additional awards granted in 2008 and higher costs related to the performance share program. The performance share costs are related to additional units awarded and the increase in the market price of CNX Gas common stock in 2008.

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. Incentive compensation expense increased $2 million when compared to the prior year due to improved performance relative to the targets.

56

Miscellaneous Other Corporate Expenses decreased $1 million due various items that occurred during both periods, none of which were individually significant.

Interest expense increased $2 million in the year-to-year comparison. Interest expense increased $1 million due to an increase in outstanding principal on the revolving credit facility. Miscellaneous interest increased $1 million due to various transactions that occurred throughout both years, none of which were individually material.

OTHER SEGMENT ANALYSIS for the year ended December 31, 2008 compared to the year ended December 31, 2007

	For the Years Ended December 31,
										Percentage
	2008			2007			Variance			Change
Sales-Outside	$	316		$	235		$	81		34.5	%
Other Income		16			15			1		6.7	%
Total Revenue		332			250			82		32.8	%
Cost of Goods Sold and Other Charges		324			238			86		36.1	%
Depreciation, Depletion & Amortization		20			19			1		5.3	%
Taxes Other Than Income Tax		11			12			(1	)	(8.3	)%
Total Costs		355			269			86		32.0	%
Earnings Before Income Tax		(23	)		(19	)		(4	)	(21.1	)%
Income Tax		240			136			104		76.5	%
Net Income	$	(263	)	$	(155	)	$	(108	)	(69.7	)%

The Other segment includes activity from sales of industrial supplies, the transportation operations and various other corporate activities that are not allocated to the coal or gas segment. The other segment negatively contributed $23 million to total company earnings before income tax for the year ended December 31, 2008 compared to a negative contribution of $19 million for the year ended December 31, 2007. The other segment also includes total company income tax expense of $240 million for the year ended December 31, 2008 compared to $136 million for the year ended December 31, 2007.

Industrial supplies:

Total revenue from industrial supplies was $197 million for the year ended December 31, 2008 compared to $148 million for the year ended December 31, 2007. The $49 million increase in revenues from the sale of industrial supplies was primarily due to the July 2007 acquisition of Piping & Equipment, Inc. in addition to an overall increase in sales volumes and higher sales prices.

Total costs related to industrial supplies were $191 million for the year ended December 31, 2008 compared to $144 million for the year ended December 31, 2007. The $47 million increase was primarily due to the July 2007 acquisition of Piping & Equipment, Inc. The increase was also related to additional volumes of goods sold and higher costs throughout 2008.

Transportation operation:

Total revenue related to the transportation operations was $133 million for the year ended December 31, 2008 compared to $93 million for the year ended December 31, 2007. The increase was primarily related to revenue generated from the barge towing operations having higher average rates for services rendered compared to the prior year. The barge towing operations have also increased thru-put tons and delivered tons in 2008. The higher terminal revenues were offset, in part, due to services being suspended for approximately one month due to maintenance needed on a pier in Baltimore.

Total costs related to the transportation operations were $101 million for the year ended December 31, 2008 compared to $75 million for the year ended December 31, 2007. The increase of $26 million was primarily due to increased fuel charges resulting from higher fuel prices and increased operating hours. Costs also have increased due to the acquisition of Tri-River Fleeting on October 3, 2007, as well as higher thru-put volumes in 2008.

57

Miscellaneous Other:

Other income was $2 million for the year ended December 31, 2008 compared to $9 million for the year ended December 31, 2007. The increase is related to various transactions that have 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 $63 million for the year ended December 31, 2008 compared to $50 million in the year ended December 31, 2007. 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. Due mainly to the downturn in the economy, it is not probable that the company can repay these loans, or that the company will complete a public offering. Therefore, the asset values have been written down.

The remaining $7 million increase is attributable to various transactions that occurred throughout both periods, none of where were individually material.

The effective income tax rate was 33.1% for the year ended December 31, 2008 compared to 31.7% for the year ended December 31, 2007. The effective tax rate is sensitive to the relationship between pre-tax earnings and percentage depletion. The proportion of coal per-tax earnings and gas pre-tax earnings also impact the benefit of percentage of depletion on the effective tax rate. See “Note 6-Income Taxes” in Item 8, Consolidated Financial Statements of this Form 8-K.

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

58

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

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

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

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CONSOL Energy Inc. (and Subsidiaries) at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

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

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

Ernst & Young LLP

Pittsburgh, Pennsylvania

February 9, 2010, except for Note 25,

as to which the date is September 21, 2010

59

Report of Independent Registered Public Accounting Firm

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

In our opinion, the consolidated statements of income, stockholders’ equity and cash flows for the year ended December 31, 2007 present fairly, in all material respects, the results of CONSOL Energy Inc. and its subsidiaries (CONSOL Energy) operations and their cash flows for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule (not presented herein) listed in the index appearing under Item 15(a)(2) of CONSOL Energy Inc.’s 2009 Annual Report on Form 10-K presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of CONSOL Energy’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 18, 2008, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the change in accounting for non-controlling interests discussed in Note 1 to the consolidated financial statements, as to which the date is June 26, 2009, and except for the change in the composition of reportable segments discussed in Note 25, as to which the date is September 21, 2010

60

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)

	For the Years Ended December 31,
	2009			2008			2007
Sales—Outside	$	4,311,791		$	4,181,569		$	3,324,346
Sales—Purchased Gas		7,040			8,464			7,628
Sales—Gas Royalty Interests		40,951			79,302			46,586
Freight—Outside		148,907			216,968			186,909
Other Income (Note 3)		113,186			166,142			196,728
Total Revenue and Other Income		4,621,875			4,652,445			3,762,197
Cost of Goods Sold and Other Operating Charges (exclusive of depreciation, depletion and amortization shown below)		2,757,052			2,843,203			2,352,000
Purchased Gas Costs		6,442			8,175			7,162
Gas Royalty Interests Costs		32,376			73,962			39,921
Freight Expense		148,907			216,968			186,909
Selling, General and Administrative Expenses		130,704			124,543			108,664
Depreciation, Depletion and Amortization		437,417			389,621			324,715
Interest Expense (Note 4)		31,419			36,183			30,851
Taxes Other Than Income (Note 5)		289,941			289,990			258,926
Black Lung Excise Tax Refund		(728	)		(55,795	)		24,092
Total Costs		3,833,530			3,926,850			3,333,240
Earnings Before Income Taxes		788,345			725,595			428,957
Income Taxes (Note 6)		221,203			239,934			136,137
Net Income		567,142			485,661			292,820
Less: Net Income Attributable to Noncontrolling Interest		(27,425	)		(43,191	)		(25,038	)
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	539,717		$	442,470		$	267,782
Earnings Per Share (Note 1):
Basic	$	2.99		$	2.43		$	1.47
Dilutive	$	2.95		$	2.40		$	1.45
Weighted Average Number of Common Shares Outstanding (Note 1):
Basic		180,693,243			182,386,011			182,050,627
Dilutive		182,821,136			184,679,592			184,149,751
Dividends Paid Per Share	$	0.40		$	0.40		$	0.31

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

61

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)

	December 31,
	2009			2008
ASSETS
Current Assets:
Cash and Cash Equivalents	$	65,607		$	138,512
Accounts and Notes Receivable:
Trade		317,460			221,729
Other Receivables		15,983			79,552
Inventories (Note 8)		307,597			227,810
Recoverable Income Taxes		—			33,862
Deferred Income Taxes (Note 6)		73,383			60,599
Prepaid Expenses		161,006			221,750
Total Current Assets		941,036			983,814
Property, Plant and Equipment:
Property, Plant and Equipment		10,681,955			9,980,288
Less—Accumulated Depreciation, Depletion and Amortization		4,557,665			4,214,316
Total Property, Plant and Equipment—Net (Note 10)		6,124,290			5,765,972
Other Assets:
Deferred Income Taxes (Note 6)		425,297			333,543
Investment in Affiliates		83,533			72,996
Other		151,245			214,133
Total Other Assets		660,075			620,672
TOTAL ASSETS	$	7,725,401		$	7,370,458
LIABILITIES AND EQUITY
Current Liabilities:
Accounts Payable	$	269,560		$	385,197
Short-Term Notes Payable (Note 11)		472,850			557,700
Current Portion of Long-Term Debt (Note 13 and Note 14)		45,394			22,401
Accrued Income Taxes		27,944			—
Other Accrued Liabilities (Note 12)		612,838			546,442
Total Current Liabilities		1,428,586			1,511,740
Long-Term Debt:
Long-Term Debt (Note 13)		363,729			393,312
Capital Lease Obligations (Note 14)		59,179			75,039
Total Long-Term Debt		422,908			468,351
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions (Note 15)		2,679,346			2,493,344
Pneumoconiosis Benefits (Note 16)		184,965			190,261
Mine Closing		397,320			404,629
Gas Well Closing		85,992			80,554
Workers’ Compensation (Note 16)		152,486			128,477
Salary Retirement (Note 15)		189,697			194,567
Reclamation		27,105			38,193
Other		132,517			185,996
Total Deferred Credits and Other Liabilities		3,849,428			3,716,021
TOTAL LIABILITIES		5,700,922			5,696,112
Stockholders’ Equity:
Common Stock, $.01 Par Value; 500,000,000 Shares Authorized, 183,014,426 Issued and 181,086,267 Outstanding at December 31, 2009; 183,014,426 Issued and 180,549,851 Outstanding at December 31, 2008		1,830			1,830
Capital in Excess of Par Value		1,033,616			993,478
Preferred Stock, 15,000,000 authorized, None issued and outstanding		—			—
Retained Earnings		1,456,898			1,010,902
Accumulated Other Comprehensive Loss (Note 19)		(640,504	)		(461,900	)
Common Stock in Treasury, at Cost—1,928,159 Shares at December 31, 2009 and 2,464,575 Shares at December 31, 2008		(66,292	)		(82,123	)
Total CONSOL Energy Inc. Stockholders’ Equity		1,785,548			1,462,187
Noncontrolling Interest		238,931			212,159
TOTAL EQUITY		2,024,479			1,674,346
TOTAL LIABILITIES AND EQUITY	$	7,725,401		$	7,370,458

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

62

CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands, except per share data)

	Common Stock			Capital  in Excess of Par Value			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Common Stock in Treasury			Total CONSOL Energy, Inc. Stockholders’ Equity			Non- Controlling Interest			Total Equity
Balance at December 31, 2006	$	1,851		$	921,881		$	600,541		$	(375,717	)	$	(82,405	)	$	1,066,151		$	135,659		$	1,201,810
Net Income		—			—			267,782			—			—			267,782			25,038			292,820
Treasury Rate Lock (Net of $52 Tax)		—			—			—			(81	)		—			(81	)		—			(81	)
Gas Cash Flow Hedge (Net of $2,146 Tax)		—			—			—			3,445			—			3,445			769			4,214
Actuarially Determined Long-Term Liability Adjustments (Net of $27,991 Tax)		—			—			—			(46,931	)		—			(46,931	)		(78	)		(47,009	)
Comprehensive Income (Loss)		—			—			267,782			(43,567	)		—			224,215			25,729			249,944
Cumulative Effect of Adoption of Income Tax Uncertainties		—			—			(3,202	)		—			—			(3,202	)		—			(3,202	)
Issuance of Treasury Stock		—			—			(42,110	)		—			61,334			19,224			—			19,224
Issuance of CNX Gas Stock		—			—			—			—			—			—			215			215
Purchases of Treasury Stock		—			—			—			—			(80,157	)		(80,157	)		—			(80,157	)
Purchases of CNX Gas Stock		—			—			—			—			—			—			(1,762	)		(1,762	)
Tax Benefit From Stock-Based Compensation		—			23,682			—			—			—			23,682			16			23,698
Amortization of Stock-Based Compensation Awards		—			20,981			—			—			—			20,981			3,261			24,242
Dividends ($0.31 per share)		—						(56,475	)		—			—			(56,475	)		—			(56,475	)
Balance at December 31, 2007		1,851			966,544			766,536			(419,284	)		(101,228	)		1,214,419			163,118			1,377,537
Net Income		—			—			442,470			—			—			442,470			43,191			485,661
Treasury Rate Lock (Net of $55 Tax)		—			—			—			(77	)		—			(77	)		—			(77	)
Gas Cash Flow Hedge (Net of $77,292 Tax)		—			—			—			97,833			—			97,833			20,813			118,646
Actuarially Determined Long-Term Liability Adjustments (Net of $82,156 Tax)		—			—			—			(140,289	)		—			(140,289	)		(16	)		(140,305	)
Comprehensive Income (Loss)		—			—			442,470			(42,533	)		—			399,937			63,988			463,925
Adoption of Actuarially Determined Long-Term Liability Measurement Provision (Net of $23,652 Tax)		—			—			(38,606	)		(83	)		—			(38,689	)		(18	)		(38,707	)
Issuance of Treasury Stock		—			—			(21,519	)		—			34,980			13,461			—			13,461
Issuance of CNX Gas Stock		—			—			—			—			—			—			312			312
Purchases of Treasury Stock		—			—			—			—			(15,875	)		(15,875	)		—			(15,875	)
Purchases of CNX Gas Stock		—			—			—			—			—			—			(18,682	)		(18,682	)
Retirement of Common Stock (2,112,200 Shares)		(21	)		(16,876	)		(65,022	)		—			—			(81,919	)		—			(81,919	)
Tax Benefit From Stock-Based Compensation		—			22,003			—			—			—			22,003			62			22,065
Amortization of Stock-Based Compensation Awards		—			21,807			—			—			—			21,807			3,379			25,186
Dividends ($0.40 per share)		—			—			(72,957	)		—			—			(72,957	)		—			(72,957	)
Balance at December 31, 2008		1,830			993,478			1,010,902			(461,900	)		(82,123	)		1,462,187			212,159			1,674,346
Net Income		—			—			539,717			—			—			539,717			27,425			567,142
Treasury Rate Lock (Net of $49 Tax)		—			—			—			(83	)		—			(83	)		—			(83	)
Gas Cash Flow Hedge (Net of $34,932 Tax)		—			—			—			(44,270	)		—			(44,270	)		(8,862	)		(53,132	)
Actuarially Determined Long-Term Liability Adjustments (Net of $77,361 Tax)		—			—			—			(134,251	)		—			(134,251	)		(298	)		(134,549	)
Comprehensive Income (Loss)		—			—			539,717			(178,604	)		—			361,113			18,265			379,378
Issuance of Treasury Stock		—			—			(21,429	)		—			15,831			(5,598	)		—			(5,598	)
Issuance of CNX Gas Stock		—			—			—			—			—			—			157			157
Tax Benefit From Stock-Based Compensation		—			2,674			—			—			—			2,674			13			2,687
Amortization of Stock-Based Compensation Awards		—			32,723			—			—			—			32,723			16,658			49,381
Stock-Based Compensation Awards to CNX Gas Employees		—			4,741			—			—			—			4,741			(3,951	)		790
Net Change in Crown Drilling Noncontrolling Interest		—			—			—			—			—			—			(4,370	)		(4,370	)
Dividends ($0.40 per share)		—			—			(72,292	)		—			—			(72,292	)		—			(72,292	)
Balance at December 31, 2009	$	1,830		$	1,033,616		$	1,456,898		$	(640,504	)	$	(66,292	)	$	1,785,548		$	238,931		$	2,024,479

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

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CONSOL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

(Dollars in thousands, except per share data)

	For the Years Ended December 31,
	2009			2008			2007
Cash Flows from Operating Activities:
Net Income	$	567,142		$	485,661		$	292,820
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization		437,417			389,621			324,715
Stock-based Compensation		39,032			25,186			24,243
Gain on Sale of Assets		(15,121	)		(23,368	)		(112,389	)
Amortization of Mineral Leases		3,970			4,871			4,519
Deferred Income Taxes		47,430			135,594			59,555
Equity in Earnings of Affiliates		(15,707	)		(11,140	)		(6,551	)
Changes in Operating Assets:
Accounts Receivable Securitization		(115,000	)		39,600			125,400
Accounts and Notes Receivable		84,597			(79,747	)		14,074
Inventories		(79,787	)		(53,994	)		13,448
Prepaid Expenses		10,730			(5,032	)		(9,145	)
Changes in Other Assets		(724	)		17,081			40,164
Changes in Operating Liabilities:
Accounts Payable		(70,458	)		64,851			(2,435	)
Other Operating Liabilities		80,527			(14,020	)		(30,978	)
Changes in Other Liabilities		(45,883	)		51,546			(54,924	)
Other		17,286			2,754			1,517
Net Cash Provided by Operating Activities		945,451			1,029,464			684,033
Cash Flows from Investing Activities:
Capital Expenditures		(920,080	)		(1,061,669	)		(743,114	)
Acquisition of AMVEST		—			—			(296,724	)
Proceeds from Sale of Assets		69,884			28,193			84,791
Purchase of Stock in Subsidiary		—			(67,259	)		(10,000	)
Net Investment in Equity Affiliates		4,855			1,879			(7,057	)
Net Cash Used in Investing Activities		(845,341	)		(1,098,856	)		(972,104	)
Cash Flows from Financing Activities:
Payments on Long-Term Debt		—			—			(45,000	)
(Payments on) Proceeds from Short-Term Debt		(84,850	)		310,200			247,500
Payments on Miscellaneous Borrowings		(19,190	)		(10,414	)		(2,935	)
Tax Benefit from Stock-Based Compensation		3,270			22,003			23,682
Dividends Paid		(72,292	)		(72,957	)		(56,475	)
Issuance of Treasury Stock		2,547			15,215			19,224
Purchases of Treasury Stock		—			(97,794	)		(80,157	)
Noncontrolling Interest Member Distribution		(2,500	)		—			—
Net Cash (Used In) Provided By Financing Activities		(173,015	)		166,253			105,839
Net Increase (Decrease) in Cash and Cash Equivalents		(72,905	)		96,861			(182,232	)
Cash and Cash Equivalents at Beginning of Period		138,512			41,651			223,883
Cash and Cash Equivalents at End of Period	$	65,607		$	138,512		$	41,651

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

See Note 20—Supplemental Cash Flow

64

CONSOL ENERGY INC. AND SUBSIDIARIES

NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 1—Significant Accounting Policies:

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

Basis of Consolidation:

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

Use of Estimates:

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

Cash and Cash Equivalents:

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

Trade Accounts Receivable:

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

Inventories:

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

Property, Plant and Equipment:

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

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

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

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

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

Gas wells are accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, but at least once a year; those revisions are accounted for prospectively as changes in accounting estimates.

Depreciation of mining plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows:

	Years
Building and improvements	10 to 45
Mine machinery and equipment	3 to 25
Leasehold improvements	Life of Lease

Costs to obtain coal lands are capitalized based on the fair value at acquisition and are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned and accessible to the mine. Proven and probable coal reserves exclude non-recoverable coal reserves and anticipated processing losses. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is produced. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material income effect from changes in estimates is disclosed in the period the change occurs.

Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material income effect from changes in estimates is disclosed in the period the change occurs. Amortization of development cost begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.

Costs for purchased and internally developed software are expensed until it has been determined that the software will result in probable future economic benefits and management has committed to funding the project. Thereafter, all direct costs of materials and services incurred in developing or obtaining software, including certain payroll and benefit costs of employees associated with the project, are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed 7 years.

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Impairment of Long-lived Assets:

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the assets’ carrying value. Impairment expense of $4,211 was recognized in Cost of Goods Sold and Other Operating Charges for the year ended December 31, 2009 for the impairment of certain sales contract assets. Impairment expense of $3,773 was recognized in Cost of Goods Sold and Other Operating Charges in December 2008, when it became probable that an option to purchase preferred equity in PFBC Environment Energy Technology would not be exercised.

Income Taxes:

Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in CONSOL Energy’s financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of CONSOL Energy’s assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized.

As required by the Income Tax Topic of the FASB Accounting Standards Codification, CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement, is determined. A previously recognized tax position is derecognized when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution of identified matters.

Postretirement Benefits Other Than Pensions:

Postretirement benefits other than pensions, except for those established pursuant to the Coal Industry Retiree Health Benefit Act of 1992 (the Health Benefit Act), are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the FASB Accounting Standards Codification which requires employers to accrue the cost of such retirement benefits for the employees’ active service periods. Such liabilities are determined on an actuarial basis and CONSOL Energy is primarily self-insured for these benefits. Postretirement benefit obligations established by the Health Benefit Act are treated as a multi-employer plan which requires expense to be recorded for the associated obligations as payments are made. This treatment is in accordance with the Retirement Benefits Compensation (Extractive Activities—Mining) Topic of the FASB Accounting Standards Codification.

Pneumoconiosis Benefits and Workers’ Compensation:

CONSOL Energy is required by federal and state statutes to provide benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers’ pneumoconiosis. CONSOL Energy is also required by various state statutes to provide workers’ compensation benefits for employees who sustain employment related physical injuries or some types of occupational disease. Workers’ compensation benefits include compensation for their disability, medical costs, and on some occasions, the cost of rehabilitation. CONSOL Energy is primarily self-insured for these benefits. Provisions for estimated benefits are determined on an actuarial basis.

Mine Closing, Reclamation and Gas Well Closing:

CONSOL Energy accrues for reclamation costs, mine closing costs, perpetual water care costs and dismantling and removing costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Depreciation of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in the Cost of Goods Sold and Other Operating Charges line on the Consolidated Statements of Income. Asset retirement obligations primarily relate to the closure of mines and gas wells, and includes treatment of water and the reclamation of land upon exhaustion of coal and gas reserves.

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Accrued mine closing costs, perpetual care costs, reclamation and costs of dismantling and removing gas related facilities are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements.

Retirement Plans:

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer retirement plans. Effective January 1, 2007, employees hired by CNX Gas, an 83.3% owned subsidiary, will not be eligible to participate in the non-contributory defined benefit retirement plan. In lieu of participation in this plan, these employees began receiving an additional 3% company contribution into their defined contribution plan.

Revenue Recognition:

Revenues are recognized when title passes to the customers. For domestic coal sales, this generally occurs when coal is loaded at mine or offsite storage locations. For export coal sales, this generally occurs when coal is loaded onto marine vessels at terminal locations. For gas sales, this occurs at the contractual point of delivery. For industrial supplies and equipment sales, this generally occurs when the products are delivered. For terminal, river and dock, land, research and development, and coal waste disposal services, revenue is recognized generally as the service is provided to the customer.

CNX Gas has operational gas-balancing agreements with various interstate pipelines. These imbalance agreements are managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken by the purchaser.

CNX Gas sells gas to accommodate the delivery points of its customers. In general this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty which qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are therefore reflected net on the income statement in Cost of Goods Sold and Other Operating Charges.

CNX Gas also provides gathering services to third parties by purchasing gas produced by the third party, at market prices less a fee. The gas purchased from third party producers is then resold by CNX Gas to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as purchased gas revenue and purchased gas costs in the Consolidated Statements of Income. Purchased gas revenue is recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CNX Gas from the third party producer.

Royalty Interest Gas Sales represent the revenues for the portion of production associated with royalty interest owners.

Freight Revenue and Expenses:

Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight Revenue and Freight Expense, respectively.

Royalty Recognition:

Royalty expenses for coal rights are included in Cost of Goods Sold and Other Operating Charges when the related revenue for the coal sale is recognized. Royalty expenses for gas rights are included in Gas Royalty Interest Costs when the related revenue for the gas sale is recognized. These royalty expenses are paid in cash in accordance with the terms of each agreement. Revenues for coal and gas sold related to production under royalty contracts, versus owned by CONSOL Energy, are recorded on a gross basis. The recognized revenues for these transactions are not net of related royalty fees.

Contingencies:

CONSOL Energy, or our subsidiaries, from time to time is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense and are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.

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Treasury Stock:

On September 12, 2008, CONSOL Energy’s Board of Directors announced a share repurchase program of up to $500,000 of the company’s common stock during a twenty-four month period beginning September 9, 2008, and ending September 8, 2010. Shares of common stock repurchased by us are recorded at cost as treasury stock and result in a reduction of stockholders’ equity in our Consolidated Balance Sheets. From time to time, treasury shares may be reissued as part of our stock-based compensation programs. When shares are reissued, we use the weighted average cost method for determining cost. The difference between the cost of the shares and the issuance price is added to or deducted from Capital in Excess of Par Value.

On December 21, 2005, CONSOL Energy’s Board of Directors announced a share repurchase program of up to $300,000 of the company’s common stock during a twenty-four month period beginning January 1, 2006 and ending December 31, 2007.

For the years ended December 31, 2008 and 2007, we had cash expenditures under our repurchase program of $97,794 and $80,157, respectively, funded primarily by cash generated from operations. The total common shares repurchased for the years ended December 31, 2008 and 2007 were 2,741,300 and 2,087,800 at an average cost of $35.59 and $38.14 per share, respectively. There were no cash expenditures under our repurchase program for the year ended December 31, 2009.

Stock-Based Compensation:

Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of Stock Compensation Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the option vesting term. See Note 18 to the Audited Consolidated Financial Statements for a further discussion on stock-based compensation.

Earnings per Share:

Basic earnings per share are computed by dividing net earnings by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similar to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, and the assumed vesting of restricted and performance stock units if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised, and outstanding restricted and performance stock units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. In accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification, CONSOL Energy includes the impact of the proforma deferred tax assets in determining potential windfalls and shortfalls for purposes of calculating assumed proceeds under the treasury stock method. The table below sets forth the outstanding options, unvested restricted stock units, and unvested performance stock units that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive.

	For the Years Ended December 31,
	2009		2008		2007
Anti-Dilutive Options		695,743		370,987		133,343
Anti-Dilutive Restricted Stock Units		5,274		—		—
Anti-Dilutive Performance Stock Units		41,581		18,176		—
		742,598		389,163		133,343
	For the Years Ended December 31,
	2009		2008		2007
Net income attributable to CONSOL Energy Inc. shareholders	$	539,717	$	442,470	$	267,782
Average shares of common stock outstanding:
Basic		180,693,243		182,386,011		182,050,627
Effect of stock-based compensation awards		2,127,893		2,293,581		2,099,124
Dilutive		182,821,136		184,679,592		184,149,751
Earnings per share:
Basic	$	2.99	$	2.43	$	1.47
Dilutive	$	2.95	$	2.40	$	1.45

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Shares of common stock outstanding were as follows:

	2009	2008		2007
Balance, beginning of year	180,549,851	182,291,623		182,654,629
Issuance(1)	536,416	1,027,250		1,755,457
Repurchased-Treasury Stock Shares	—	(656,922	)	(2,118,463	)
Repurchased-Retired Shares	—	(2,112,100	)	—
Balance, end of year	181,086,267	180,549,851		182,291,623

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

Accounting for Derivative Instruments:

CONSOL Energy accounts for derivative instruments in accordance with the Derivatives and Hedging Topic of the FASB Accounting Standards Codification. This requires CONSOL Energy to measure every derivative instrument (including certain derivative instruments embedded in other contracts) at fair value and record them in the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported, net of applicable taxes, in other comprehensive income. The ineffective portions of hedges are recognized in earnings in the current period.

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

Accounting for Business Combinations:

The company accounts for its business acquisitions under the purchase method of accounting consistent with the requirements of the Business Combination Topic of the FASB Accounting Standards Codification. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.

Accounting for Carbon Emissions Offsets:

In 2008, CNX Gas, an 83.3% subsidiary, completed the independent verification and registration processes necessary to sell carbon emission offsets on the Chicago Climate Exchange. CNX Gas has verified approximately 8.4 million metric tons of offsets, CONSOL Energy has also verified approximately 8.3 million metric tons of offsets which may sell on the over-the-counter market. These offsets are recorded at their historical cost, which is zero. Sales of these emission offsets will be reflected in income as they occur. To date, no offsets have been sold.

Recently Adopted Accounting Guidance:

In December 2009, CONSOL adopted authoritative guidance issued by the FASB on extractive activities for oil and gas reserve estimation and disclosures. The objective of the new guidance is to align the oil and gas reserve estimation and disclosure requirements with the requirements of the Securities and Exchange Commission. The new guidance, among other purposes, is primarily intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves by expanding the definition of proved oil and gas producing activities, disclosing geographical areas that represent a certain percentage of proved reserves, updating the reserve estimation requirements for changes in practice and technology that have occurred over the past several decades and requiring that an entity continue to disclose separately the amounts and quantities for consolidated and equity method investments. CONSOL has applied this guidance to its Financial Statements for the year ended December 31, 2009.

Recent Accounting Guidance Not Yet Adopted:

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

In June 2009, the FASB issued accounting guidance regarding the accounting for transfers of financial assets that is designed to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and

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

Reclassifications:

Certain reclassifications of prior period data have been made to conform to the year ended December 31, 2009 as required by the Noncontrolling Interest Topic of the FASB Accounting Standards Codification.

Subsequent Events:

We have evaluated all subsequent events through February 9, 2010, the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.

Note 2—Acquisitions and Dispositions:

In August 2009, CONSOL Energy completed the lease assignment of CNX Gas’, an 83.3% owned subsidiary, previous headquarters. Total expense related to this transaction for the year ended December 31, 2009 was $1,500, which was recognized in the Cost of Goods Sold and Other Operating Charges.

In August 2009, CONSOL Energy completed a sale/lease-back of longwall shields for Bailey Mine. Cash proceeds from the sale were $16,011, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.

In July 2009, CNX Gas leased approximately 20,000 acres having Marcellus Shale potential from NiSource Energy Ventures, LLC, a subsidiary of the Columbia Energy Group, for a cash payment of $8,275 which is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statement of Cash Flows. The purchase price for the transaction was principally allocated to gas properties and related development.

In June 2009, CONSOL Energy recognized the fair value of the remaining lease payments in the amount of $10,499 in accordance with the Exit or Disposal Cost Obligations topic of the Financial Accounting Standards Board Accounting Standards Codification related to the Company’s previous headquarters. This liability has been recorded in Other Liabilities on the consolidated balance sheet at December 31, 2009. Total expense related to this transaction was $12,500, which was recognized in the Cost of Goods Sold and Other Operating Charges. This amount includes lease payments of $10,974 as well as the removal of a related asset of $1,526. Additionally, $5,832 was recognized in the Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the premises that occurred in 2005.

In February 2009, CONSOL Energy completed a sale/lease-back of longwall shields for Bailey Mine. Cash proceeds for the sale were $42,282, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.

In December 2008, CONSOL Energy completed the acquisition of the outstanding 51% interest in Southern West Virginia Energy, LLC (“SWVE”) for a cash payment of $11,521. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statement of Cash Flows. The purchase price was principally allocated to property, plant and equipment. SWVE wholly-owns Southern West Virginia Resources, LLC and Minway Contracting, LLC, and had previously been a 49% subsidiary of CONSOL Energy. Prior to the acquisition of the outstanding interest, SWVE had been fully consolidated in accordance with the Consolidation Topic of the Financial Accounting Standards Board Accounting Standards Codification by CONSOL Energy. The proforma results for this acquisition are not material to CONSOL Energy’s financial results.

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In November 2008, CONSOL Energy completed the acquisition of North Penn Pipe & Supply, Inc. for a cash payment, net of cash acquired, of $22,550. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statements of Cash Flows. North Penn Pipe & Supply, Inc. is a distributor of oil and gas field equipment, primarily tubular goods, to the northern Appalachian Basin, a region stretching from the state of New York to southwestern Pennsylvania and northern West Virginia. The fair value of merchandise for resale acquired in this acquisition is $10,623 and is included in inventory on the Consolidated Balance Sheets as of the acquisition date. The pro forma results for this acquisition are not significant to CONSOL Energy’s financial results.

In October 2008 CONSOL Energy Inc.’s Board of Directors has authorized a purchase program for shares of CNX Gas Corporation common stock for an aggregate purchase price of up to $150 million. The authorization, which is not intended to take CNX Gas private, was effective as of October 21, 2008 for a twenty-four month period. During the year ended December 31, 2008, CONSOL Energy completed the purchase of $67,259 of CNX Gas stock on the open market at an average price of $26.53 per share. The purchase of these 2,531,400 shares changed CONSOL Energy’s ownership percentage in CNX Gas from 81.7% to 83.3% at December 31, 2008. During the year ended December 31, 2007, CONSOL Energy purchased $10,000 of CNX Gas stock on the open market at an average price of $26.87 per share. The purchase of these 372,000 shares changed CONSOL Energy’s ownership percentage in CNX Gas from 81.5% to 81.7% at December 31, 2007.

In July 2008, CNX Gas completed the acquisition of several leases and gas wells from KIS Oil & Gas Inc. for a cash payment of $19,324. The purchase price was principally allocated to property, plant and equipment. The sales agreement called for the transfer of 30 oil and gas wells and approximately 5,600 leased acres. This acquisition enhanced our acreage position in Northern Appalachia. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.

In June 2008, CNX Gas completed the acquisition of the remaining 50% interest in Knox Energy, LLC and Coalfield Pipeline Company not already owned by CNX Gas for a cash payment of $36,000 which was principally allocated to gas properties and related development and gas gathering equipment. Knox Energy, LLC had been proportionately consolidated into CONSOL Energy’s financial statements during 2008. During 2007 the equity method was used to account for these entities. Knox Energy, LLC is a natural gas production company and Coalfield Pipeline Company is a gathering and transportation company with operations in Tennessee. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.

In February 2008, CONSOL Energy completed the sale of the Mill Creek Mining Complex located in Kentucky. The sales agreement called for the transfer of all of the assets comprising the complex. Cash proceeds from the sale were $14,649, with our basis in the assets being $9,934. Accordingly, a gain of $4,715 was recorded on the transaction.

In December 2007, CONSOL Energy completed a sale/lease-back of 35 river barges. Cash proceeds from the sale were $16,895, with our basis in the equipment being $16,951. Accordingly, a loss of $56 was recorded on the transaction. The lease has been accounted for as an operating lease. The lease term is fourteen years.

In October 2007, CONSOL Energy acquired 100% of the outstanding shares in an oil and gas company for a cash payment of $12,385 which was principally allocated to gas properties and related development and gas gathering equipment. The acquired company is in the business of owning, operating and producing oil and gas wells and related pipelines. The acquired assets consisted of gas wells, equipment and connecting pipelines utilized in well operations. The acquisition was accounted for according to the Business Combination Topic of the Financial Accounting Standards Board Accounting Standards Codification. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.

In July, 2007, CONSOL Energy acquired 100% of the voting interest of AMVEST Corporation and certain subsidiaries and affiliates (AMVEST) for a cash payment, net of cash acquired, of $296,724 in a transaction accounted for according to the Business Combination Topic of the Financial Accounting Standards Board Accounting Standards Codification. The coal reserves acquired consisted of approximately 160 million tons of high quality, low sulfur steam and high-volatile metallurgical coal. Also included in the acquisition were four coal preparation plants, several fleets of modern mining equipment and a common short-line railroad that connects the coal preparation plants to the CSX and Norfolk and Southern rail interchanges. The results of operations of the acquired entities are included in CONSOL Energy’s Consolidated Statements of Income as of August 1, 2007.

The AMVEST acquisition, when combined with CONSOL Energy’s adjacent coal reserves, creates a large contiguous block of coal reserves in the Central Appalachian region. Also, included in the acquisition was a highly-skilled workforce proficient in Central Appalachian surface mining. This workforce combined with CONSOL Energy’s underground mining expertise will allow us to build and transfer knowledge among operations to focus the best skill sets to development requirements of the various parts of this reserve block.

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The unaudited pro forma results, assuming the acquisition had occurred at January 1, 2007 are estimated to be:

	For the Year  Ended December 31, 2007
Revenue	$	3,902,186
Earnings Before Taxes	$	444,409
Net Income	$	279,074
Basic Earnings Per Share	$	1.53
Dilutive Earnings Per Share	$	1.52

The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of 2007, nor are they necessarily indicative of future consolidated results.

In July 2007, CONSOL Energy completed the acquisition of Piping & Equipment, Inc. for a cash payment, net of cash acquired, of $16,914. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statements of Cash Flows. Piping & Equipment, Inc. is a pipe, valve and fittings supplier with eight locations in Florida, Alabama, Louisiana and Texas. The fair value of merchandise for resale acquired in this acquisition is $8,481 and is included in inventory on the Consolidated Balance Sheets. The pro forma results for this acquisition are not significant to CONSOL Energy’s financial results.

In June 2007, CONSOL Energy exchanged certain coal assets in Northern Appalachia with Peabody Energy for coalbed methane and gas rights. This transaction was accounted for as a non-monetary exchange under the Fair Value Measurements and Disclosures Topic of the Financial Accounting Standards Board Accounting Standards Codification resulting in a pre-tax gain of $50,060. Also in June 2007, CONSOL Energy, through a subsidiary, acquired certain coalbed methane and gas rights from Peabody Energy for a cash payment of $15,000 plus approximately $1,650 of various other acquisition costs.

In June 2007, CONSOL Energy sold the rights to certain western Kentucky coal in the Illinois Basin to Alliance Resource Partners, L.P. for $53,309. This transaction resulted in a pre-tax gain of $49,868.

Note 3—Other Income:

	For the Years Ended December 31,
	2009		2008		2007
Royalty income	$	17,249	$	20,673	$	14,205
Equity in earnings of affiliates		15,707		11,140		6,551
Gain on disposition of assets		15,121		23,368		112,389
Contract settlements		12,450		—		—
Service income		11,796		14,298		12,623
Interest income		5,052		2,363		12,792
Charter & tramp towing income		4,838		11,164		2,601
Buchanan roof collapse insurance proceeds		—		50,000		10,000
Other		30,973		33,136		25,567
Total Other Income	$	113,186	$	166,142	$	196,728

Note 4—Interest Expense:

	For the Years Ended December 31,
	2009			2008			2007
Interest on debt	$	39,524		$	45,627		$	40,766
Interest on other payables		3,766			2,718			4,648
Interest capitalized		(11,871	)		(12,162	)		(14,563	)
Total Interest Expense	$	31,419		$	36,183		$	30,851

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Note 5—Taxes Other Than Income:

	For the Years Ended December 31,
	2009			2008			2007
Production taxes	$	183,307		$	188,581		$	163,346
Payroll taxes		48,702			49,829			43,828
Property taxes		47,934			44,107			41,586
Capital stock & franchise tax		8,895			6,568			7,475
Virginia employment enhancement tax credit		(3,715	)		(4,190	)		(3,159	)
Other		4,818			5,095			5,850
Total Taxes Other Than Income	$	289,941		$	289,990		$	258,926

Note 6—Income Taxes:

Income taxes (benefits) provided on earnings consisted of:

	For the Years Ended December 31,
	2009			2008		2007
Current:
U.S. Federal	$	134,231		$	87,658	$	62,704
U.S. State		41,482			14,549		11,284
Non-U.S.		(1,940	)		2,133		2,594
		173,773			104,340		76,582
Deferred:
U.S. Federal		49,672			101,869		40,278
U.S. State		(2,242	)		33,725		19,277
		47,430			135,594		59,555
Total Income Taxes	$	221,203		$	239,934	$	136,137

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

	December 31,
	2009			2008
Deferred Tax Assets:
Postretirement benefits other than pensions	$	1,084,523		$	990,336
Mine closing		134,362			133,591
Alternative minimum tax		102,029			168,276
Pneumoconiosis benefits		81,724			75,124
Workers’ compensation		69,562			59,687
Salary retirement		68,820			74,967
Net operating loss		53,133			57,370
Capital lease		31,301			32,212
Reclamation		11,946			14,581
Other		120,911			78,923
Total Deferred Tax Assets		1,758,311			1,685,067
Valuation Allowance**		(61,623	)		(60,898	)
Net Deferred Tax Assets		1,696,688			1,624,169
Deferred Tax Liabilities:
Property, plant and equipment		(1,103,585	)		(1,085,054	)
Gas hedge		(46,129	)		(81,061	)
Advance mining royalties		(25,568	)		(23,445	)
Other		(22,726	)		(40,467	)
Total Deferred Tax Liabilities		(1,198,008	)		(1,230,027	)
Net Deferred Tax Assets	$	498,680		$	394,142

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** Valuation allowances of ($3,051) and ($58,572) have been allocated between current and long-term deferred tax assets respectively for 2009. Valuation allowances of ($2,663) and ($58,235) have been allocated between current and long-term deferred tax assets respectively for 2008.

A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. For the years ended December 31, 2009 and 2008, positive evidence considered included future income projections based on existing fixed price contracts and forecasted expenses, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence included financial and tax losses generated in prior periods and the inability to achieve forecasted results for those periods.

In 2007, CONSOL Energy implemented a prudent and feasible tax strategy that ensured the realization of Pennsylvania loss carry forward tax benefits. For 2009 and 2008, CONSOL Energy continues to report a deferred tax asset of $16,081 and $22,656 on an after federal tax adjusted basis relating to the remainder of its state operating loss carry forwards after valuation allowances, respectively. A review of the positive and negative evidence regarding these tax benefits, primarily the history of financial and tax losses on a separate company basis, concluded that the valuation allowances were warranted. A valuation allowance of $24,571 and $26,184 on an after federal tax adjusted basis has also been recorded for 2009 and 2008 respectively, against the deferred state tax asset attributable to future deductible temporary differences for certain CONSOL Energy subsidiaries with histories of financial and tax losses. The net operating loss carryforwards expire at various times between 2010 and 2027. Management will continue to assess the potential for realizing deferred tax assets based upon income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods as appropriate, that could materially impact net income. Included in the valuation allowance against the deferred state tax assets attributable to future deductible temporary differences for 2009 and 2008 are $7,952 and $8,496, respectively, of future tax benefits relating to other postretirement, pension and long-term disability benefits which are subject to a full valuation allowance. The decrease in the valuation allowances recognized related to other postretirement, pension and long-term disability benefits were recognized through Other Comprehensive Income in the applicable period.

We estimate that CONSOL Energy will utilize federal alternative minimum tax credits of $60,032 for the year ended December 31, 2009, thereby reducing the deferred tax asset associated with the prior years’ minimum tax credits. During 2009, the federal alternative minimum tax credits were increased $3,631 as a result of the 2008 accrual to 2008 return adjustments. As a result of the conclusion of the Internal Revenue Service (IRS) examination of the 2004 and 2005 tax returns, CONSOL Energy was able to utilize an additional $9,846 of alternative minimum tax credits.

The following is a reconciliation stated as a percentage of pretax income, of the United States statutory federal income tax rate to CONSOL Energy’s effective tax rate:

	For the Years Ended December 31,
	2009					2008					2007
	Amount			Percent		Amount			Percent		Amount			Percent
Statutory U.S. federal income tax rate	$	275,921		35.0	%	$	253,958		35.0	%	$	150,135		35.0	%
Excess tax depletion		(68,787	)	(8.7	)		(48,859	)	(6.7	)		(43,502	)	(10.1	)
Effect of medicare prescription drug, improvement and modernization act of 2003		2,112		0.3			2,112		0.3			1,796		0.4
Effect of domestic production activities		(12,707	)	(1.6	)		(7,721	)	(1.1	)		(915	)	(0.2	)
Net effect of state tax		25,377		3.2			31,169		4.3			20,086		4.7
Effect of foreign tax		(343	)	—			2,133		0.3			787		0.2
Other		(370	)	(0.1	)		7,142		1.0			7,750		1.7
Income Tax Expense/Effective Rate	$	221,203		28.1	%	$	239,934		33.1	%	$	136,137		31.7	%

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

	For the Years Ended December 31,
	2009			2008
Balance at beginning of period	$	84,554		$	91,696
Increase in unrecognized tax benefits resulting from tax positions taken during current period		17,461			11,725
Increase (decrease) in unrecognized tax benefits resulting from tax positions taken during prior period		7,825			(18,867	)
Reduction in unrecognized tax benefits as a result of the lapse of the applicable statute of limitations		(3,800	)		—
Reduction of unrecognized tax benefits as a result of a settlement with taxing authorities		(27,229	)		—
Balance at end of period	$	78,811		$	84,554

If these unrecognized tax benefits were recognized, $15,502 and $14,657 respectively would affect CONSOL Energy’s effective income tax rate.

CONSOL Energy and its subsidiaries file income tax returns in the U.S. federal, various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for the years before 2005. During the year ended December 31, 2009, CONSOL Energy was advised by the Canadian Revenue Agency that its appeal of tax deficiencies paid as a result of the Agency’s audit of the Company’s Canadian tax returns filed for years 1997 through 2002 had been successfully resolved. The Company recorded a tax refund receivable of $4,560 as a result of the audit settlement.

During the year ended December 31, 2009, CONSOL Energy paid federal and state income tax deficiencies of $12,798 and $608, respectively. The federal and state deficiencies paid, as a result of the 2004 and 2005 tax returns, had an insignificant impact on net income due to the tax deficiencies being the result of changes in the timing of certain tax deductions.

The IRS is commencing its audit of CONSOL Energy’s income tax returns filed for 2006 and 2007. The Company expects to conclude this examination and remit payment of any resulting tax deficiencies to federal and state taxing authorities before December 31, 2010. Since the IRS examination is in its initial stages, any resulting tax deficiency or overpayment cannot be estimated at this time. During the next year the statute of limitations for assessing additional income tax deficiencies will expire for certain tax years in several state tax jurisdictions. The expiration of the statute of limitations for these years will have an insignificant impact on CONSOL Energy’s total uncertain income tax positions and net income for the twelve-month period.

CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. At December 31, 2009 and 2008, the Company had an accrued liability of $8,338 and $10,518, respectively, for interest related to uncertain tax positions. The accrued interest liabilities include $2,409, $2,012 and $3,426 that were recorded in the Company’s Consolidated Statements of Income for the years ended December 31, 2009 and 2008, respectively. During the year ended December 31, 2009, CONSOL Energy paid interest of $4,590 related to income tax deficiencies to the IRS as a result of its examinations of the Company’s tax returns filed for the years 2002 through 2005.

CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2009 and 2008, there were no accrued penalties recognized.

Note 7—Mine Closing, Reclamation & Gas Well Closing:

CONSOL Energy accrues for reclamation, mine closing costs, perpetual water care costs and dismantling and removing costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes capitalized asset retirement costs by increasing the carrying amount of related long-lived assets, net of the associated accumulated depreciation. The obligation for asset retirements is included in Mine Closing, Reclamation, Gas Well Closing and Other Accrued Liabilities on the Consolidated Balance Sheets.

The reconciliation of changes in the asset retirement obligations at December 31, 2009 and 2008 is as follows:

	As of December 31,
	2009			2008
Balance at beginning of period	$	544,314		$	530,897
Accretion expense		39,610			34,888
Payments		(31,458	)		(32,085	)
Revisions in estimated cash flows		(19,006	)		30,409
Other		(283	)		(19,795	)
Balance at end of period	$	533,177		$	544,314

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For the year ended December 31, 2009, Other includes ($283) of various other items, none of which are individually significant. For the year ended December 31, 2008, Other includes ($19,618) for asset dispositions and ($177) of various other items, none of which are individually significant.

Note 8—Inventories:

Inventory components consist of the following:

	December 31,
	2009		2008
Coal	$	173,719	$	93,875
Merchandise for resale		44,842		43,074
Supplies		89,036		90,861
Total Inventories	$	307,597	$	227,810

Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $13,696 and $14,716 at December 31, 2009 and 2008, respectively.

Note 9—Accounts Receivable Securitization:

CONSOL Energy and certain of our U.S subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. This facility allows CONSOL Energy to receive up to $165,000 on a revolving basis. The facility also allows for the issuance of letters of credit against the $165,000 capacity. At December 31, 2009, there were no letters of credit outstanding against the facility.

CONSOL Energy formed CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary for the sole purpose of buying and selling eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocable and without recourse, sell all of their eligible trade accounts receivable to financial institutions and their affiliates, while maintaining a subordinated interest in a portion of the pool of trade receivables. This retained interest, which is included in Accounts and Notes Receivable Trade in the Consolidated Balance Sheets, is recorded at fair value. Due to the short average collection cycle for the receivables that are part of this program, the fair value of our retained interest approximates the total amount of the designated pool of accounts receivable reduced by the amount of accounts receivables sold to the third-party financial institutions under the program. CONSOL Energy will continue to service the trade receivables for the financial institutions for a fee based upon market rates for similar services.

The cost of funds under this facility is based upon commercial paper rates, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $2,990 and $5,814 for the year ended December 31, 2009 and 2008, respectively. These costs have been recorded as financing fees, which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in April 2012 with the underlying liquidity agreement renewing annually each April.

At December 31, 2009 and 2008, eligible accounts receivable totaled approximately $151,000 and $165,000, respectively. The subordinated retained interest approximated $101,000 at December 31, 2009. There was no subordinated retained interest at December 31, 2008. Accounts receivable totaling $50,000 and $165,000 were removed from the Consolidated Balance Sheets at December 31, 2009 and 2008, respectively. In accordance with the facility agreement, the company is able to receive proceeds based upon total eligible accounts receivable at the previous month end. CONSOL Energy’s $115,000 decrease and $39,600 increase in the accounts receivable securitization program for the years ended December 31, 2009 and 2008, respectively, is reflected in cash flows from operating activities in the Consolidated Statements of Cash Flows.

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Note 10—Property, Plant and Equipment

	December 31,
	2009		2008
Coal and other plant and equipment	$	4,874,880	$	4,533,793
Coal properties and surface lands		1,284,795		1,264,920
Gas properties and related development		1,649,476		1,427,588
Gas gathering equipment		804,212		740,396
Airshafts		622,068		615,512
Leased coal lands		504,475		502,521
Mine development		573,037		527,991
Coal advance mining royalties		366,312		365,380
Gas advance royalties		2,700		2,187
Total Property, Plant and Equipment		10,681,955		9,980,288
Less—Accumulated depreciation, depletion and amortization		4,557,665		4,214,316
Net Property, Plant and Equipment	$	6,124,290	$	5,765,972

Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary greatly; however, the lease terms generally are extended automatically to the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction, and are legally considered real property interests. We also make advance payments (advanced mining royalties) to lessors under certain lease agreements that are recoupable against future production, and we make payments that are generally based upon a specified rate per ton or a percentage of gross realization from the sale of the coal. We evaluate our properties periodically for impairment issues or whenever events or circumstances indicate that the carrying amount may not be recoverable.

Coal reserves are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned or accessible to the mine. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is placed into production. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material income effect from changes in estimates is disclosed in the period the change occurs.

Amortization of capitalized mine development costs associated with a coal reserve is computed on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material income effect from changes in estimates is disclosed in the period the change occurs. Amortization of development costs begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.

Amortization of wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised whenever there is an indication of the need for a revision, but at least once a year, and accounted for prospectively.

Gas wells are accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, but at least once a year; those revisions are accounted for prospectively as changes in accounting estimates.

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The following assets are amortized using the units-of-production method. Amounts reflect properties where mining or drilling operations have not yet commenced and therefore are not yet being amortized for the years ended December 31, 2009 and 2008, respectively.

	December 31,
	2009		2008
Coal properties and surface lands	$	393,368	$	395,880
Gas properties and related development		271,125		220,848
Airshafts		63,673		70,017
Leased coal lands		254,081		260,699
Mine development		114,800		98,842
Coal advance mining royalties		12,494		31,725
Gas advance royalties		2,405		2,187
Total	$	1,111,946	$	1,080,198

As of December 31, 2009 and 2008, plant and equipment includes gross assets under capital lease of $81,770 and $112,890, respectively. As of December 31, 2008, the Northern Appalachian coal segment maintained a $37,018 capital lease for longwall shields at Enlow Fork, which was included in Coal and other plant and equipment. In addition, for the years ended December 31, 2009 and 2008, the Gas segment maintains a capital lease for the Jewell Ridge Pipeline of $66,919, which is included in Gas gathering equipment. For the years ended December 31, 2009 and 2008, the Gas segment also maintains a capital lease for vehicles of $2,788 and $3,071, respectively, which are included in Gas properties and related development. For the years ended December 31, 2009 and 2008, the All Other segment maintains a capital lease for vehicles of $12,063 and $5,882, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was $21,893 and $31,929 at December 31, 2009 and 2008, respectively. Amortization expense for capital leases is included in depreciation expense. See Note 14—Leases for additional capital lease details.

Note 11—Short-Term Notes Payable:

CONSOL Energy has a five-year $1,000,000 senior secured credit facility, which extends through June 2012. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in 2012. The Agreement does provide for the release of collateral at the request of CONSOL Energy upon achievement of certain credit ratings. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 4.50 to 1.00, measured quarterly. The interest coverage ratio was 24.78 to 1.00 at December 31, 2009. The facility also includes a maximum leverage ratio covenant of not more than 3.25 to 1.00, measured quarterly. The leverage ratio was 0.87 to 1.00 at December 31, 2009. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends and merge with another corporation. At December 31, 2009, the $1,000,000 facility had $415,000 of borrowings outstanding and $268,360 of letters of credit outstanding, leaving $316,640 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 0.86% and 1.71% as of December 31, 2009 and 2008, respectively.

CNX Gas has a five-year $200,000 unsecured credit agreement which extends through October 2010. The agreement contains a negative pledge provision, whereas CNX Gas assets cannot be used to secure other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, purchase or redeem CNX Gas stock, pay dividends and merge with another corporation. The facility includes a maximum leverage ratio covenant of not more than 3.00 to 1.00, measured quarterly. The leverage ratio was 0.38 to 1.00 at December 31, 2009. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 68.17 to 1.00 at December 31, 2009. At December 31, 2009, the CNX Gas credit agreement had $57,850 of borrowings outstanding and $14,913 of letters of credit outstanding, leaving $127,237 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 1.69% and 2.01% as of December 31, 2009 and 2008, respectively.

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Note 12—Other Accrued Liabilities:

	December 31,
	2009		2008
Subsidence liability	$	72,390	$	54,013
Accrued payroll and benefits		50,696		59,765
Accrued other taxes		42,559		41,916
Uncertain income tax positions		42,423		28,903
Short-term incentive compensation		35,710		29,329
Royalties		24,098		33,857
Other		112,095		78,925
Current portion of long-term liabilities:
Postretirement benefits other than pensions		164,747		145,429
Workers’ compensation		27,885		32,778
Mine closing		19,568		16,833
Pneumoconiosis benefits		9,676		9,833
Reclamation		3,192		4,108
Long term disability		5,468		5,389
Salary retirement		2,331		2,034
Deferred revenue		—		3,330
Total Other Accrued Liabilities	$	612,838	$	546,442

Note 13—Long-Term Debt:

	December 31,
	2009		2008
Debt:
Secured notes due March 2012 at 7.875% (par value of $250,000 less unamortized discount of $447 at December 31, 2009)	$	249,553	$	249,346
Baltimore Port Facility revenue bonds in series due December 2010 at 6.50%		30,865		30,865
Baltimore Port Facility revenue bonds in series due October 2011 at 6.50%		72,000		72,000
Advance royalty commitments		35,547		30,019
Notes due through 2011 at 6.10%		14,628		18,936
Other long-term notes maturing at various dates through 2031 (total value of $164 less unamortized discount of $4 at December 31, 2009)		160		1,121
		402,753		402,287
Less amounts due in one year		39,024		8,975
Total Long-Term Debt	$	363,729	$	393,312

Advance royalty commitments and the other long-term variable rate notes had a weighted average interest rate of approximately 7.36% at December 31, 2009 and 10.65% at December 31, 2008. The bonds and notes are carried net of debt discount, which is being amortized over the life of the issue.

Annual undiscounted maturities on long-term debt during the next five years are as follows:

Year Ended December 31,	Amount
2010	$	39,024
2011		85,344
2012		253,057
2013		2,847
2014		2,574
Thereafter		20,358
Total Long-Term Debt Maturities	$	403,204

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Note 14—Leases:

CONSOL Energy uses various leased facilities and equipment in our operations. Future minimum lease payments under capital and operating leases, together with the present value of the net minimum capital lease payments, at December 31, 2009, are as follows:

Year Ended December 31, 2009	Capital Leases		Operating Leases
2010	$	10,997	$	79,649
2011		9,977		73,012
2012		8,641		54,562
2013		7,718		51,044
2014		7,469		41,900
Thereafter		50,379		166,358
Total minimum lease payments	$	95,181	$	466,525
Less amount representing interest (0.63% - 7.36%)		29,632
Present value of minimum lease payments		65,549
Less amount due in one year		6,370
Total Long-Term Capital Lease Obligation	$	59,179

Rental expense under operating leases was $77,960, $63,170 and $47,765 for the years ended December 31, 2009, 2008 and 2007, respectively.

Note 15—Pension and Other Postretirement Benefit Plans:

CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer plans. The benefits for these plans are based primarily on years of service and employee’s pay near retirement.

The CONSOL Energy salaried plan allows for lump-sum distributions of benefits earned up until December 31, 2005 at the employees’ election. As of January 1, 2006, lump sum benefits have been frozen and prospectively the lump sum option has been eliminated. According to the Defined Benefit Plans Topic of the FASB Accounting Standards Codification, if the lump sum distributions made for the plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the service cost and interest cost for the plan year, settlement accounting is required. Lump sum payments did not exceed the threshold during 2009 or 2008. Lump sum payments exceeded this threshold during 2007. Accordingly, CONSOL Energy recognized expense of $2,734 for the year ended December 31, 2007 in the results of operations. The adjustment equaled the unrecognized actuarial loss resulting from each individual who received a lump sum in that year. CONSOL Energy regularly monitors this situation.

During the year ended December 31, 2009, certain former and existing CNX Gas employees became eligible to participate in the CONSOL Energy Supplemental Retirement Plan. The additional benefit liabilities for these employees have been reflected as Plan Amendments in the reconciliation of the changes in benefit obligation for the year ended December 31, 2009.

Effective January 1, 2007, employees hired by CNX Gas, an 83.3% owned subsidiary, will not be eligible to participate in CNX Gas’ non-contributory defined benefit retirement plan. In lieu of participation in the non-contributory defined benefit retirement plan, these employees began receiving an additional 3% company contribution into their defined contribution plan.

Certain subsidiaries of CONSOL Energy provide medical and life insurance benefits to retired employees not covered by the Coal Industry Retiree Health Benefit Act of 1992. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare. Prior to August 1, 2003, substantially all employees became eligible for these benefits if they had ten years of company service and attained age 55. Effective August 1, 2003, the base eligibility was changed to age 55 with 20 years of service for salaried employees. In addition, effective January 1, 2004, a medical plan cost sharing arrangement with all salaried employees and retirees was adopted. These participants will now contribute a target of 20% of the medical plan operating costs. Contributions may be higher, dependent on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared by CONSOL Energy and the participants. Annual cost increases in excess of 6% will be the sole responsibility of the participants. Also, any salaried or non-represented hourly employees that were hired or rehired effective January 1, 2007, or later, will not become eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of two thousand two hundred and fifty dollars for each year of service at retirement. Newly employed inexperienced employees represented by the United Mine Workers of America, hired after January 1, 2007, will not be eligible to receive retiree benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked.

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CONSOL Energy adopted the measurement provisions of the Defined Benefit Plans Topic of the FASB Accounting Standards Codification during the year ended December 31, 2008. As a result of the adoption, the Company recognized an increase of $2,278 and $42,599 in the liabilities for pension and other postretirement benefits, respectively. These increases were accounted for as a reduction in the January 1, 2008 balance of retained earnings.

The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2009 and 2008, is as follows:

	Pension Benefits at December 31,						Other Benefits at December 31,
	2009			2008			2009			2008
Change in benefit obligation:
Benefit obligation at beginning of period	$	571,772		$	523,381		$	2,638,773		$	2,484,829
Contractual liability(a)		—			103			—			2,486
Service cost (9/30/07-12/31/07)		—			2,438			—			2,639
Service cost		12,332			9,752			12,654			10,554
Interest cost (9/30/07-12/31/07)		—			8,257			—			39,960
Interest cost		35,483			33,029			151,451			159,837
Actuarial loss		78,529			54,243			197,066			95,372
Plan amendments		3,371			49			—			22,456
Participant contributions (9/30/07-12/31/07)		—			—			—			1,221
Participant contributions		—			—			4,633			4,884
Benefits paid (9/30/07-12/31/07)		—			(12,536	)		—			(37,545	)
Benefits paid		(47,465	)		(46,944	)		(160,484	)		(147,920	)
Benefit obligation at end of period	$	654,022		$	571,772		$	2,844,093		$	2,638,773
Change in plan assets:
Fair value of plan assets at beginning of period	$	375,261		$	453,203		$	—		$	—
Actual return on plan assets		66,537			(60,256	)		—			—
Company contributions (9/30/07-12/31/07)		—			905			—			36,323
Company contributions		67,667			42,080			155,851			143,036
Participant contributions (9/30/07-12/31/07)		—			—			—			1,221
Participant contributions		—			—			4,633			4,884
Benefits and other payments (9/30/07-12/31/07)		—			(12,536	)		—			(37,544	)
Benefits and other payments		(47,465	)		(48,135	)		(160,484	)		(147,920	)
Fair value of plan assets at end of period	$	462,000		$	375,261		$	—		$	—
Funded status:
Noncurrent assets	$	6		$	90		$	—		$	—
Current liabilities		(2,331	)		(2,034	)		(164,747	)		(145,429	)
Noncurrent liabilities		(189,697	)		(194,567	)		(2,679,346	)		(2,493,344	)
Net obligation recognized	$	(192,022	)	$	(196,511	)	$	(2,844,093	)	$	(2,638,773	)
Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial loss	$	362,901		$	336,541		$	1,152,630		$	1,005,922
Prior service credit		(3,141	)		(7,621	)		(168,561	)		(214,976	)
Net amount recognized (before tax effect)	$	359,760		$	328,920		$	984,069		$	790,946

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The components of net periodic benefit costs are as follows:

	Pension Benefits									Other Benefits
	For the Years Ended December 31,									For the Years Ended December 31,
	2009			2008			2007			2009			2008			2007
Components of net periodic benefit cost:
Service cost	$	12,332		$	9,752		$	11,015		$	12,654		$	10,555		$	10,988
Interest cost		35,483			33,029			28,710			151,451			159,837			139,221
Expected return on plan assets		(36,631	)		(33,671	)		(30,656	)		—			—			—
Settlement		—			—			2,734			—			—			—
Amortization of prior service cost (credit)		(1,109	)		(1,114	)		(1,114	)		(46,415	)		(48,625	)		(51,001	)
Recognized net actuarial loss		22,263			16,728			12,487			50,357			61,503			61,230
Benefit cost	$	32,338		$	24,724		$	23,176		$	168,047		$	183,270		$	160,438

Amounts included in accumulated other comprehensive income, expected to be recognized in 2010 net periodic benefit costs:

	Pension Benefits			Postretirement Benefits
Prior service cost (benefit) recognition	$	(735	)	$	(46,415	)
Actuarial loss recognition	$	31,460		$	69,593

The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan assets:

	As of December 31,
	2009		2008
Projected benefit obligation	$	653,925	$	571,155
Accumulated benefit obligation	$	580,498	$	511,275
Fair value of plan assets	$	462,000	$	374,657

Assumptions:

The weighted-average assumptions used to determine benefit obligations are as follows:

	Pension Benefits For the Year Ended December 31,				Other Benefits For the Year Ended December 31,
	2009		2008		2009		2008
Discount rate	5.79	%	6.28	%	5.87	%	6.20	%
Rate of compensation increase	4.09	%	4.05	%	—		—

The weighted-average assumptions used to determine net periodic benefit costs are as follows:

	Pension Benefits at December 31,						Other Benefits at December 31,
	2009		2008		2007		2009		2008		2007
Discount rate	6.28	%	6.57	%	6.00	%	6.20	%	6.63	%	6.00	%
Expected long-term return on plan assets	8.00	%	8.00	%	8.00	%	—		—		—
Rate of compensation increase	4.05	%	4.01	%	3.65	%	—		—		—

The long-term rate of return is the sum of the portion of total assets in each asset class held multiplied by the expected return for that class, adjusted for expected expenses to be paid from the assets. The expected return for each class is determined using the plan asset allocation at the measurement date and a distribution of compound average returns over a 20-year time horizon. The model uses asset class returns, variances and correlation assumptions to produce the expected return for each portfolio. The return assumptions used forward-looking gross returns influenced by the current Treasury yield curve. These returns recognize current bond yields, corporate bond spreads and equity risk premiums based on current market conditions.

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The assumed health care cost trend rates are as follows:

	At December 31,
	2009		2008		2007
Health care cost trend rate for next year	8.74	%	9.60	%	8.00	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	4.50	%	5.00	%	5.00	%
Year that the rate reaches ultimate trend rate	2023		2015		2013

Assumed health care cost trend rates have a significant effect on the amounts reported for the medical plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:

	1-Percentage Point Increase		1-Percentage Point Decrease
Effect on total of service and interest costs components	$	19,901	$	(17,043	)
Effect on accumulated postretirement benefit obligation	$	318,777	$	(276,481	)

Assumed discount rates also have a significant effect on the amounts reported for both pension and other benefit costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:

	0.25 Percentage Point Increase			0.25 Percentage Point Decrease
Pension benefit costs (decrease) increase	$	(750	)	$	740
Other postemployment benefits costs (decrease) increase	$	(3,833	)	$	3,779

Plan Assets:

The company’s overall investment strategy for its pension plan assets is to meet current and future benefit payment needs through diversification across asset classes, fund strategies and fund managers to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation. The target allocations for plan assets are 36 percent U.S. equity securities, 24 percent non-U.S. equity securities 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, 2009 by asset category are as follows:

	Fair Value Measurements at December 31, 2009
Asset Category	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash	$	231	$	231	$	—	$	—
US Equities(a)		3		3		—		—
MGI Collective Trusts
US Large Cap Growth Equity(b)		42,186		—		42,186		—
US Large Cap Value Equity(c)		41,205		—		41,205		—
US Small/Mid Cap Growth Equity(d)		17,069		—		17,069		—
US Small/Mid Cap Value Equity(e)		16,826		—		16,826		—
US Core Fixed Income(f)		17,755		—		17,755		—
Non-US Core Equity(g)		110,747		—		110,747		—
US Long Duration Investment Grade Fixed Income(h)		41,261		—		41,261		—
US Long Duration Fixed Income(i)		58,466		—		58,466		—
US Large Cap Passive Equity(j)		52,255		—		52,255		—
US Passive Fixed Income(k)		12,999		—		12,999		—
US Long Duration Passive Fixed Income(l)		23,589		—		23,589		—
US Ultra Long Duration Fixed Income(m)		27,408		—		27,408		—
Total	$	462,000	$	234	$	461,766	$	—

(a) This category includes investments in United States common stocks.

(b) This category invests primarily in common stock of large cap companies in the U.S. with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Russell 1000 Growth Index.

(c) This category invests primarily in U.S. large cap companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Russell 1000 Value Index.

(d) This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.

(e) This category invests in small to mid-sized U.S. companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.

(f) This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest in opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targeted to be within 20% of the benchmark’s duration. Total exposure to high yield issues is typically less than 10%, inclusive of direct investment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.

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(g) This category invests in all cap companies operating in developed and emerging markets outside the U.S. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the MSCI EAFE Index.

(h) This category invests in a passively managed U.S. long duration investment grade portfolio at a 90% weight and a passively managed U.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing for short term liquidity through a strategic allocation to U.S. Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% to the Barclays Capital Long Treasury.

(i) This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 11 years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds, and TIPs. The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.

(j) This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.

(k) This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Aggregate Index.

(l) This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 11 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.

(m) This category seeks to reduce the volatility of the plan’s funded status and extend the duration of the assets by investing in a series of ultra long duration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return in excess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets to the plan’s liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.

There are no direct investments in CONSOL Energy stock held by these plans at December 31, 2009 or 2008.

There are no assets in the other postretirement benefit plans at December 31, 2009 or 2008.

Cash Flows:

CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Currently, depending on asset values and asset returns held in the trust, we expect to contribute $63,600 to our pension plan trust in 2010. Pension benefit payments are primarily funded from the trust. CONSOL Energy does not expect to contribute to the other postemployment plan in 2010. We intend to pay benefit claims as they are due.

The following benefit payments, reflecting expected future service, are expected to be paid:

	Pension Benefits		Other Benefits
2010	$	38,212	$	164,747
2011	$	36,358	$	175,356
2012	$	44,017	$	182,548
2013	$	44,445	$	189,550
2014	$	47,684	$	196,119
Year 2015-2019	$	269,407	$	1,040,248

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Note 16—Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation:

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. CONSOL Energy primarily provides for these claims through a self-insurance program. The calculation of the actuarial present value of the estimated pneumoconiosis obligation is based on an annual actuarial study by independent actuaries. The calculation is based on assumptions regarding disability incidence, medical costs, indemnity levels, mortality, death benefits, dependents and interest rates. These assumptions are derived from actual company experience and outside sources. Actuarial gains associated with CWP have resulted from numerous legislative changes over many years which have resulted in lower approval rates for filed claims than our assumptions originally reflected. Actuarial gains have also resulted from lower incident rates and lower severity of claims filed than our assumption originally reflected.

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 health care trend rate, benefit duration and recurrence of injuries. Actuarial gains associated with workers’ compensation have resulted from discount rate changes, several years of favorable claims experience, various favorable state legislation changes and overall lower incident rates than our assumptions.

CONSOL Energy adopted the measurement provisions of the Defined Benefit Plans Topic of the FASB Accounting Standards Codification during the year ended December 31, 2008. As a result of this adoption, the Company recognized an increase of $4,871 and $11,523 in liabilities for coal workers’ pneumoconiosis and workers’ compensation, respectively. These increases were accounted for as a reduction in the January 1, 2008 balance of retained earnings.

	CWP December 31,						Workers’ Compensation December 31,
	2009			2008			2009			2008
Change in benefit obligation:
Benefit obligation at beginning of period	$	200,094		$	182,872		$	159,761		$	162,060
Contractual liability(a)		—			1,689			—			355
State administrative fees and insurance bond premiums		—			—			6,710			5,509
Service cost (9/30-12/31)		—			1,934			—			7,257
Service cost		9,774			7,736			31,795			29,030
Interest cost (9/30-12/31)		—			2,937			—			2,082
Interest cost		12,054			11,748			8,765			8,328
Actuarial (gain) loss		(16,584	)		4,117			9,825			(4,236	)
Benefits paid (9/30-12/31)		—			(1,455	)		—			(11,834	)
Benefits paid		(10,697	)		(11,484	)		(37,588	)		(38,790	)
Benefit obligation at end of period	$	194,641		$	200,094		$	179,268		$	159,761
Current liabilities	$	(9,676	)	$	(9,833	)	$	(27,885	)	$	(32,778	)
Noncurrent liabilities		(184,965	)		(190,261	)		(151,383	)		(126,983	)
Net obligation recognized	$	(194,641	)	$	(200,094	)	$	(179,268	)	$	(159,761	)
Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial gain	$	(184,666	)	$	(187,672	)	$	(45,232	)	$	(59,257	)
Prior service credit		(1,851	)		(2,579	)		—			—
Net amount recognized (before tax effect)	$	(186,517	)	$	(190,251	)	$	(45,232	)	$	(59,257	)

(a) Amounts offset by a contractual receivable included in Other Assets on the Consolidated Balance Sheets.

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The components of the net periodic cost (credit) are as follows:

	CWP For the Years Ended December 31,									Workers’ Compensation For the Years Ended December 31,
	2009			2008			2007			2009			2008			2007
Components of Net Periodic Cost (Credit):
Service cost	$	7,074		$	5,036		$	5,856		$	28,394		$	29,030		$	29,659
Interest cost		12,054			11,748			11,401			8,765			8,328			8,356
Legal and administrative costs		2,700			2,700			2,700			3,401			3,224			3,259
Amortization of prior service cost		(728	)		(728	)		(728	)		—			—			—
Recognized net actuarial gain		(19,590	)		(23,383	)		(22,371	)		(4,200	)		(4,938	)		(3,953	)
State administrative fees and insurance bond premiums		—			—			—			6,710			5,509			10,591
Net periodic cost (credit)	$	1,510		$	(4,627	)	$	(3,142	)	$	43,070		$	41,153		$	47,912

Amounts included in accumulated other comprehensive income, expected to be recognized in 2010 net periodic benefit costs:

	CWP Benefits			Workers’ Compensation Benefits
Prior service benefit recognition	$	(728	)	$	—
Actuarial gain recognition	$	(19,196	)	$	(3,072	)

Assumptions:

The weighted-average discount rate used to determine benefit obligations and net periodic (benefit) cost are as follows:

	CWP For Years Ended December 31,						Workers’ Compensation For Years Ended December 31,
	2009		2008		2007		2009		2008		2007
Benefit obligations	5.84	%	6.23	%	6.62	%	5.55	%	5.90	%	5.94	%
Net Periodic (benefit) costs	6.23	%	6.62	%	6.00	%	5.90	%	5.94	%	6.00	%

Assumed discount rates have a significant effect on the amounts reported for both CWP benefits and Workers’ Compensation costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:

	0.25 Percentage Point Increase			0.25 Percentage Point Decrease
CWP benefit (decrease) increase	$	(655	)	$	643
Workers’ Compensation costs (decrease) increase	$	(29	)	$	23

Cash Flows:

CONSOL Energy does not intend to make contributions to the CWP or Workers’ Compensation plans in 2010. We intend to pay benefit claims as they become due.

The following benefit payments, which reflect expected future claims as appropriate, are expected to be paid:

			Workers’ Compensation
	CWP Benefits		Total Benefits		Actuarial Benefits		Other Benefits
2010	$	9,676	$	34,359	$	27,885	$	6,474
2011	$	10,217	$	35,989	$	29,256	$	6,733
2012	$	10,791	$	37,365	$	30,363	$	7,002
2013	$	11,351	$	38,507	$	31,225	$	7,282
2014	$	11,885	$	39,437	$	31,863	$	7,574
Year 2015-2019	$	65,428	$	204,744	$	162,081	$	42,663

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Note 17—Other Employee Benefit Plans:

UMWA Pension and Benefit Trusts:

Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan negotiated with the United Mine Workers of America (the UMWA) and contained in the National Bituminous Coal Wage Agreement (the NBCWA). The NBCWA currently calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The current contribution rates called for by the NBCWA are: $4.25 per hour worked in 2009, $5.00 per hour worked in 2010 and $5.50 per hour worked in 2011. Total contributions for a year may differ from total expenses for the year due to the timing of actual contributions compared to the date of assessment. Total contributions to the UMWA 1974 Pension Trust were $25,620, $21,140 and $11,354 for the years ended December 31, 2009, 2008 and 2007, respectively. These multi-employer pension plan contributions are expensed as incurred. The Pension Protection Act requires a minimum funding ratio of 80% be maintained for this multi-employer pension plan and if the plan is determined to have a funded ratio of less than 80% it will be deemed to be “endangered” or “seriously endangered”, and if less than 65%, it will be deemed to be in “critical” status, and will in either case be subject to additional funding requirements. Under the Pension Act, the multi-employer plan’s actuary must certify the plan’s funded status for each plan year. Based on an estimated funded percentage of 91.4%, a certification was provided by the multi-employer plan actuary, stating that the 1974 Pension Trust was in neither “endangered” nor “critical” status for the plan year beginning July 1, 2008. However, the volatile economic environment and the recent rapid deterioration in the equity markets caused investment income and the value of investment assets held in the 1974 Pension Trust to decline and lose value.

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

The freeze election only applies for the 2009 plan year. If the 1974 Pension Trust is certified to be endangered, seriously endangered or in critical status for the plan year beginning July 1, 2010, steps will have to be taken under the Pension Act to improve its funded status. Such a determination would require certain subsidiaries of CONSOL Energy to make additional contributions pursuant to a funding improvement plan implemented in accordance with the Pension Act and, therefore, could have a material impact on our operating results.

The Coal Industry Retiree Health Benefit Act of 1992 (the Act) created two multi-employer benefit plans: (1) the United Mine Workers of America Combined Benefit Fund (the Combined Fund) into which the former UMWA Benefit Trusts were merged, and (2) the 1992 Benefit Fund. CONSOL Energy subsidiaries account for required contributions to these multi-employer trusts as expense when incurred.

The Combined Fund provides medical and death benefits for all beneficiaries of the former UMWA Benefit Trusts who were actually receiving benefits as of July 20, 1992. The 1992 Benefit Fund provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and who actually retired between July 20, 1992 and September 30, 1994. The Act provides for the assignment of beneficiaries to former employers and the allocation of unassigned beneficiaries (referred to as orphans) to companies using a formula set forth in the Act. The Act requires that responsibility for funding the benefits to be paid to beneficiaries be assigned to their former signatory employers or related companies. This cost is recognized when contributions are assessed. Total contributions under the Act were $22,646, $24,343 and $32,916 for the years ended December 31, 2009, 2008 and 2007, respectively. Costs were reduced in 2007 by $30,389 due to the March 2007 settlement agreement with the Combined Fund that resolved all previous issues relating to the calculation of payments to the Combined Fund. See Note 24—Commitments and Contingencies in Notes to Audited Financial Statements for additional details on the settlement agreement. Based on available information at December 31, 2009, CONSOL Energy’s obligation for the Act is estimated at approximately $182,084.

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The UMWA 1993 Benefit Plan is a defined contribution plan that was created as the result of negotiations for the NBCWA of 1993. This plan provides health care benefits to orphan UMWA retirees who are not eligible to participate in the Combined Fund, the 1992 Benefit Fund, or whose last employer signed the 1993 or a later NBCWA and who subsequently goes out of business. Contributions to the trust under the 2007 agreement are $1.44 per hour worked by UMWA represented employees for the year ended December 31, 2009, comprised of a $0.50 per hour worked under the labor agreement and $0.94 per hour worked by UMWA represented employees under the Tax Relief and Health Care Act of 2006 (the 2006 Act). Contributions to the trust under the 2007 agreement are $1.77 per hour worked by UMWA represented employees for the year ended December 31, 2008, comprised of a $0.50 per hour worked under the labor agreement and $1.27 per hour worked by UMWA represented employees under the 2006 Act. The contribution rate for the year ended December 31, 2007, was $2.00 per hour worked by UMWA represented employees, comprised of $0.50 per hour worked under the labor agreement and $1.50 per hour worked under the 2006 Act. Total contributions were $9,072, $11,494 and $11,627 for the years ended December 31, 2009, 2008 and 2007, respectively.

Pursuant to the provisions of the 2006 Act and the 1992 Plan, CONSOL Energy is required to provide security in an amount based on the annual cost of providing health care benefits for all individuals receiving benefits from the 1992 Plan who are attributable to CONSOL Energy, plus all individuals receiving benefits from an individual employer plan maintained by CONSOL Energy who are entitled to receive such benefits. In accordance with the 2006 Act and the 1992 Plan, the outstanding letters of credit to secure our obligation were $61,734 and $60,695 for years ended December 31, 2009 and 2008, respectively. The 2009 and 2008 security amounts were based on the annual cost of providing health care benefits and included a reduction in the number of eligible employees.

At December 31, 2009, approximately 34.5% of CONSOL Energy’s workforce was represented by the UMWA.

Equity Incentive Plans:

CONSOL Energy has an equity incentive plan that provides grants of stock-based awards to key employees and to non-employee directors. See Note 18 for a further discussion of CONSOL Energy’s stock-based compensation.

The CNX Gas equity incentive plan consists of the following components: stock options, stock appreciation rights, restricted stock units, performance awards, performance share units, cash awards and other stock-based awards. The total number of shares of CNX Gas common stock with respect to which awards may be granted under CNX Gas’ plan is 2,500,000. CNX Gas stock-based compensation expense, excluding allocated portions from CONSOL Energy resulted in pre-tax expense of $6,311, $3,379 and $3,260 to CONSOL Energy for the years ended December 31, 2009, 2008 and 2007, respectively.

Long Term Incentive Compensation:

CNX Gas had a long-term incentive program. This program allowed for the award of performance share units (PSUs). A PSU represents a contingent right to receive a cash payment, determined by reference to the value of one share of the Company’s common stock. The total number of units earned, if any, by a participant was based on the Company’s total stock holder return relative to the stock holder return of a pre-determined peer group of companies. CNX Gas recognized compensation costs over the requisite service period. The basis of the compensation costs was re-valued quarterly. Approximately $8,779 and $2,231 of compensation costs have been recognized for the years ended December 31, 2008 and 2007, respectively. A credit to expense of approximately $1,434 was recognized for the year ended December 31, 2009 as a result of the decline in the value of the expected payout prior to the exchange transaction discussed below.

During the second quarter of 2009, CNX Gas recognized the effect of an exchange offer that allowed participants in the CNX Gas Long-Term Incentive Program to exchange their unvested performance share units for CONSOL Energy restricted stock units. The excess fair value of the replacement restricted stock units over the original performance stock units resulted in $2,738 of incremental restricted stock compensation expense being immediately recognized. Additionally, a liability of $10,347 for the cash settlement of the CNX Gas performance share units was reclassified into equity due to the issuance of RSUs. As a result of the completed exchange offer there are no outstanding performance share units at December 31, 2009.

Investment Plan:

CONSOL Energy has an investment plan available to all domestic, non-represented employees. Effective January 1, 2006, the company match was 6% of base pay for all non-represented employees except for those employees of Fairmont Supply Company whose match remains at 50% of the first 12% of base pay. In addition, effective January 1, 2007, the definition of eligible compensation for employee deferrals and company match was amended to include overtime for all non-represented employees except for those employees of Fairmont Supply Company whose definition of eligible compensation will remain unchanged. CNX Gas employees hired on or after January 1, 2007 also receive an additional 3% non-elective contribution in lieu of participation in the CNX Gas pension plan. Total payments and costs were $24,353, $23,091 and $17,896 for the years ended December 31, 2009, 2008 and 2007, respectively.

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Long-Term Disability:

CONSOL Energy has a Long-Term Disability Plan available to all full-time salaried employees. The benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled.

	For The Years Ended December 31,
	2009			2008			2007
Benefit Costs	$	3,642		$	3,998		$	3,050
Discount rate assumption used to determine net periodic benefit oblications		5.92	%		5.92	%		5.99	%

Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities—Other and Other Accrued Liabilities and amounted to $30,097 and $29,645 for the years ended December 31, 2009 and 2008, respectively.

Note 18—Stock-Based Compensation:

CONSOL Energy adopted the CONSOL Energy Inc. Equity Incentive Plan on April 7, 1999. The plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments to the plan have been approved by the Board of Directors since the commencement of the plan. In 2009, the Board of Directors approved an increase in the total number of shares by 5,600,000 bringing the total number of shares of common stock that can be covered by grants at December 31, 2009 to 23,800,000 of which 2,600,000 are available for issuance of awards other than stock options. The Plan, as amended, will provide that the aggregate number of shares available for issuance under the Plan will be reduced by one share for each share issued in settlement of Performance Share Units (PSUs) or Restricted Stock Units (RSUs) and by 1.44 for any other award. No award of stock options may be exercised under the plan after the tenth anniversary of the effective date of the award.

In accordance with the Stock Compensation Topic of the FASB Accounting Standards Codification, CONSOL Energy recognizes stock-based compensation costs net of an estimated forfeiture rate and recognizes the compensation costs for only those shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the option vesting term, or to an employee’s eligible retirement date, if earlier and applicable. The total stock-based compensation expense recognized was $32,723, $21,807 and $20,983 for the years ended December 31, 2009, 2008 and 2007, respectively. The related deferred tax benefit totaled $12,490, $8,293 and $7,938, for the years ended December 31, 2009, 2008 and 2007, respectively.

CONSOL Energy examined its historical pattern of option exercises in an effort to determine if there were any discernable activity patterns based on certain employee populations. From this analysis, CONSOL Energy identified two distinct employee populations. CONSOL Energy used the Black-Scholes option pricing model to value the options for each of the employee populations. The table below presents the weighted average expected term in years of the two employee populations. The expected term computation is based upon historical exercise patterns and post-vesting termination behavior of the populations. The risk-free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S. Treasury obligations for the expected term of the award. The expected forfeiture rate is based upon historical forfeiture activity. A combination of historical and implied volatility is used to determine expected volatility and future stock price trends. Total fair value of options granted during the years ended December 31, 2009, 2008 and 2007 were $9,950, $11,395 and $9,912, respectively. The fair value of share-based payment awards was estimated using the Black-Scholes option pricing model with the following assumptions and weighted average fair values:

	December 31,
	2009			2008			2007
Weighted average fair value of grants	$	14.48		$	29.44		$	11.93
Risk-free interest rate		1.45	%		2.59	%		4.70	%
Expected dividend yield		1.40	%		0.50	%		0.80	%
Expected forfeiture rate		2.00	%		2.00	%		2.00	%
Expected volatility		75.60	%		46.60	%		38.20	%
Expected term in years		4.10 years			3.97 years			4.07 years

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A summary of the status of stock options granted is presented below:

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (in thousands)
Balance at December 31, 2008	4,894,864		$	26.40
Granted	687,117		$	27.89
Exercised	(167,424	)	$	15.55
Forfeited	(27,416	)	$	39.89
Balance at December 31, 2009	5,387,141		$	26.86	5.46	$	134,166
Vested and expected to vest	5,339,497		$	26.72	5.50	$	133,573
Exercisable at December 31, 2009	4,024,879		$	26.80	4.59	$	114,105

These stock options will terminate ten years after the date on which they were granted. The employee stock options, covered by the Equity Incentive Plan adopted April 7, 1999, vest 25% per year, beginning one year after the grant date for awards granted prior to 2007. Employee stock options awarded after December 31, 2006 vest 33% per year, beginning one year after the grant date. There are 4,848,213 stock options outstanding under the Equity Incentive plan. Additionally, there are 446,180 fully vested employee stock options outstanding which had vesting terms ranging from six months to one year. Non-employee director stock options vest 33% per year, beginning one year after the grant date. There are 92,747 stock options outstanding under these grants. The vesting of all options will accelerate in the event of death, disability or retirement and may accelerate upon a change in control of CONSOL Energy. In 2008, the compensation committee of the board of directors changed the retirement eligible acceleration of vesting to require a minimum vesting period of twelve months. This change is effective for all stock based compensation awards issued after January 1, 2008.

The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CONSOL Energy’s closing stock price on the last trading day of the year ended December 31, 2009, and the option’s exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2009. This amount varies based on the fair market value of CONSOL Energy’s stock. Total intrinsic value of options exercised for the year ended December 31, 2009, 2008 and 2007 was $4,502, $55,131 and $65,294, respectively.

Cash received from option exercises for the years ended December 31, 2009, 2008 and 2007 was $2,547, $15,215 and $19,224, respectively. The excess tax benefit realized for the tax deduction from option exercises totaled $3,270, $22,003 and $23,682 for the years ended December 31, 2009, 2008 and 2007, respectively. This excess tax benefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.

Under the Equity Incentive Plan, CONSOL Energy granted certain employees and non-employee directors restricted stock unit awards. These awards entitle the holder to receive shares of common stock as the award vests. Compensation expense will be recognized over the vesting period of the units. The total fair value of the restricted stock units granted during the years ended December 31, 2009, 2008 and 2007 were $42,720, $5,950 and $6,373, respectively. The total fair value of shares vested during the years ended December 31, 2009, 2008 and 2007 was $18,092, $4,720 and $3,641, respectively. The following represents the unvested restricted stock units and corresponding fair value (based upon the closing share price) at the date of grant:

	Number of Shares		Weighted Average Grant Date Fair Value
Nonvested at December 31, 2008	389,296		$	42.57
Granted	1,489,538		$	28.68
Vested	(553,701	)	$	32.68
Forfeited	(30,756	)	$	28.85
Nonvested at December 31, 2009	1,294,377		$	31.15

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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, 2009, achievement of the market and performance goals is believed to be probable. The total fair value of performance share units granted during the years ended December 31, 2009, 2008 and 2007 were $5,684, $4,904 and $3,237. The following represents the unvested performance share unit awards and their corresponding fair value (based upon the closing share price) at the date of grant:

	Number of Shares	Weighted Average Grant Date Fair Value
Nonvested at December 31, 2008	126,877	$	64.16
Granted	164,186	$	34.62
Nonvested at December 31, 2009	291,063	$	47.50

As of December 31, 2009, $24,570 of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.57 years. When employee stock options are exercised and restricted and performance share unit awards become vested, the issuances are made from CONSOL Energy’s treasury stock shares which have been acquired as part of CONSOL Energy’s share repurchase program as previously discussed in Note 1.

Note 19—Accumulated Other Comprehensive Loss:

Components of accumulated other comprehensive loss consists of the following:

	Treasury Rate Lock			Change in Fair Value of Cash Flow Hedges			Adjustments for Actuarially Determined Liabilities			Adjustments for Non- controlling Interest			Accumulated Other Comprehensive Loss
Balance at December 31, 2006	$	421		$	1,346		$	(377,484	)	$	—		$	(375,717	)
Net increase in value of cash flow hedges		—			23,943			—			(4,370	)		19,573
Reclassification of cash flow hedges from other comprehensive income to earnings		—			(19,729	)		—			3,601			(16,128	)
Current period change		(81	)		—			(47,009	)		78			(47,012	)
Balance at December 31, 2007		340			5,560			(424,493	)		(691	)		(419,284	)
Net increase in value of cash flow hedges		—			117,699			—			(20,646	)		97,053
Reclassification of cash flow hedges from other comprehensive income to earnings		—			947			—			(166	)		781
Current period change		(77	)		—			(140,305	)		19			(140,363	)
Prior period adjustment		—			—			(87	)		—			(87	)
Balance at December 31, 2008		263			124,206			(564,885	)		(21,484	)		(461,900	)
Net increase in value of cash flow hedges		—			186,824			—			(31,162	)		155,662
Reclassification of cash flow hedges from other comprehensive income to earnings		—			(239,956	)		—			40,024			(199,932	)
Current period change		(83	)		—			(134,549	)		298			(134,334	)
Balance at December 31, 2009	$	180		$	71,074		$	(699,434	)	$	(12,324	)	$	(640,504	)

The cash flow hedges that CONSOL Energy holds are disclosed in Note 23. The adjustments for Actuarially Determined Liabilities are disclosed in Note 15 and Note 16.

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Note 20—Supplemental Cash Flow Information:

	For the Years Ended December 31,
	2009			2008			2007
Cash paid during the year for:
Interest (net of amounts capitalized)	$	26,425		$	33,236		$	26,415
Income taxes	$	131,043		$	95,101		$	103,194
Non-cash investing and financing activities:
Adoption of Accounting for Uncertainty in Income Taxes
Change in Assets	$	—		$	—		$	(39,207	)
Change in Liabilities	$	—		$	—		$	(39,207	)
Businesses acquired (Note 2)
Fair value of assets acquired	$	28,113		$	(26,892	)	$	(132,694	)
Liabilities assumed	$	28,113		$	(26,892	)	$	(132,694	)
Note received from property sales	$	(1,789	)	$	—		$	(200	)
Capital Lease Obligation
Change in Assets	$	(3,375	)	$	2,622		$	(1,083	)
Change in Liabilities	$	(3,375	)	$	2,622		$	(1,083	)
Purchase of Property, Plant and Equipment
Change in Assets	$	46,938		$	(75,818	)	$	3,219
Change in Liabilities	$	46,938		$	(75,818	)	$	3,219
Accounting for Mine Closing, Reclamation and Gas Well Closing Costs
Change in Assets	$	283		$	(29,088	)	$	3,403
Change in Liabilities	$	283		$	(29,088	)	$	3,403

Note 21—Concentration of Credit Risk and Major Customers:

CONSOL Energy markets steam coal, principally to electric utilities in the United States, Canada and Western Europe, metallurgical coal to steel and coke producers worldwide, and natural gas primarily to gas wholesalers. As of December 31, 2009 and 2008, accounts receivable from utilities were $215,743 and $222,808, respectively. As of December 31, 2009 and 2008, accounts receivable from steel and coke producers were $43,448 and $40,788, respectively. As of December 31, 2009 and 2008, accounts receivable from gas wholesalers were $43,421 and $61,764, respectively. Credit is extended based on an evaluation of the customer’s financial condition, and generally collateral is not required. Credit losses have been consistently minimal.

For the years ended December 31, 2009, 2008 and 2007, no customer comprised over 10% of our revenues.

Note 22—Fair Values of Financial Instruments:

Effective January 1, 2008, CONSOL Energy adopted the provision for Fair Value of Financial Assets and Financial Liabilities as required by the Financial Accounting Standards Board Accounting Standards Codification. As a result of the adoption, CONSOL Energy elected not to measure any additional financial assets or liabilities at fair value, other than those which were previously recorded at fair value prior to the adoption.

The financial instruments measured at fair value on a recurring basis are summarized below:

	Fair Value Measurements at December 31, 2009
Description	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges	$	—	$	117,483	$	—

The following methods and assumptions were used to estimate the fair values of financial instruments, which the fair value option was not elected:

Cash and cash equivalents: The carrying amount reported in the balance sheets for cash and cash equivalents approximates its fair value due to the short maturity of these instruments.

Short-term notes payable: The carrying amount reported in the balance sheets for short-term notes payable approximates its fair value due to the short-term maturity of these instruments.

Long-term debt: The fair values of long-term debt are estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows.

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The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

	December 31, 2009						December 31, 2008
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	65,607		$	65,607		$	138,512		$	138,512
Short-term notes payable	$	(472,850	)	$	(472,850	)	$	(557,700	)	$	(557,700	)
Long-term debt	$	(402,753	)	$	(420,056	)	$	(402,287	)	$	(390,278	)

Note 23—Derivative Instruments:

CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. Our derivatives are accounted for under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification. We measure each derivative instrument at fair value and record it on the balance sheet as either an asset or liability. Changes in the fair value of the derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in Other Comprehensive Income or Loss (OCI) and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year. CONSOL Energy currently utilizes only cash flow hedges that are considered highly effective.

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

CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. All of the counterparties to CONSOL Energy’s natural gas derivative instruments also participate in CONSOL Energy’s revolving credit facility. The Company has not experienced any issues of non-performance by derivative counterparties.

CONSOL Energy has entered into forward and option contracts on various commodities to manage the price risk associated with the forecasted revenues from those commodities. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodities.

As of December 31, 2009, the total notional amount of the Company’s outstanding natural gas forward contracts was 85.1 billion cubic feet. These forward contracts are forecasted to settle through December 31, 2012 and meet the criteria for cash flow hedge accounting. During the next year, $60,307 of unrealized gain is expected to be reclassified from Other Comprehensive Income and into earnings. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

As of December 31, 2009, CONSOL Energy did not have any outstanding coal sales options. For the years ended December 31, 2009 and 2008, CONSOL Energy recognized, in Other Income on the Consolidated Statement of Income, a gain of $2,368 and a loss of ($335), respectively, for the coal sales options which were not designated as hedging instruments.

The fair value of CONSOL Energy’s derivative instruments at December 31, 2009 is as follows:

	Derivatives As of December 31, 2009
	Balance Sheet Location	Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps	Prepaid Expense	$	99,265
Natural Gas Price Swaps	Other Assets		18,218
Total derivatives designated as hedging instruments		$	117,483

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The effect of derivative instruments on the Consolidated Statement of Income for the year ended December 31, 2009 is as follows:

Derivative in Cash Flow Hedging Relationship	Amount of Gain(Loss) Recognized in OCI on Derivative 2009			Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income 2009		Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative 2009
Natural Gas Price Swaps	$	(185,862	)	Outside Sales	$	239,956	Outside Sales	$	(962	)
Total	$	(185,862	)		$	239,956		$	(962	)

The fair value of CONSOL Energy’s derivative instruments at December 31, 2008 is as follows:

	Asset Derivatives 2008			Liability Derivatives 2008
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps	Prepaid Expense	$	150,564
	Other Assets		55,945
Total derivatives designated as hedging instruments		$	206,509		$	—
Derivative not designated as hedging instruments
Coal Sales Options			—	Other Liabilities		(1,937	)
Total derivatives not designated as hedging instruments		$	—		$	(1,937	)
Total Derivatives		$	206,509		$	(1,937	)

The effect of derivative instruments on the consolidated statement of income for the year ended December 31, 2008 is as follows:

Derivative in Cash Flow Hedging Relationship	Amount of Gain(Loss) Recognized in OCI on Derivative 2008			Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income 2008			Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative 2008
Natural Gas Price Swaps	$	(118,652	)	Outside Sales	$	(947	)	Outside Sales	$	952
Total	$	(118,652	)		$	(947	)		$	952

Note 24—Commitments and Contingent Liabilities:

CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. Our current estimates related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CONSOL Energy. However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2008, the Pennsylvania Department of Conservation and Natural Resources (Commonwealth) filed a six-count Complaint in the Court of Common Pleas of Allegheny County, Pennsylvania, claiming that the Company’s underground longwall mining activities caused cracks and seepage damage to the Ryerson Park Dam, thereby eliminating the Ryerson Park Lake. The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resources damages totaling $58,000. The Court stayed the proceedings in the state court, holding that the Commonwealth should pursue administrative agency review of the claim. Furthermore, the Court found that the Commonwealth could not recover natural resources damages under applicable law. The issue of whether the dam was damaged by subsidence is being reviewed by the Department of Environmental Protection (DEP). If the DEP determines that there is causation, a second phase will be set to determine the remedy. As to the underlying claim, the Company believes it is not responsible for the damage to the dam and that numerous grounds exist upon which to attack the propriety of the claims. The Company intends to vigorously defend the case. However, it is reasonably possible that the ultimate liability in the future with respect to these claims may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

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One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 22,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi, New Jersey and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Past payments by Fairmont with respect to asbestos cases have not been material. Our current estimates related to these asbestos claims, individually and in the aggregate, are immaterial to the financial position, results of operations and cash flows of CONSOL Energy. However, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material to the financial position, results of operations or cash flows of CONSOL Energy.

CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under Superfund legislation with respect to the Ward Transformer site in Wake County, North Carolina. At that time, the EPA also identified 38 other PRPs for the Ward Transformer site. The EPA, CONSOL Energy and two other PRPs entered into an administrative Settlement Agreement and Order of Consent, requiring those PRPs to undertake and complete a PCB soil removal action, at and in the vicinity of the Ward Transformer property. Another party joined the participating PRPs and reduced CONSOL Energy’s interim allocation share from 46% to 32%. In June 2008, while conducting the PCB soil excavation on the Ward property, it was determined that PCBs have migrated onto adjacent properties.

The current estimated cost of remedial action for the area CONSOL Energy was originally named a PRP, including payment of the EPA’s past and future cost, is approximately $55,000. The current estimated cost of the most likely remediation plan for one of the additional areas discovered is approximately $10,000, although the removal action plan is not yet approved by the EPA. Also, in September 2008, the EPA notified CONSOL Energy and 60 other PRPs that there were additional areas of potential contamination allegedly related to the Ward Transformer Site. Current estimates of the cost or potential range of cost for this area are not yet available. There was $3,422, $7,080 and $1,780 of expense recognized in Cost of Goods Sold and Other Charges for the years ended December 31, 2009, 2008 and 2007, respectively. CONSOL Energy funded $5,500, $6,000 and $1,256 in the years ended December 31, 2009, 2008 and 2007, respectively, to an independent trust established for this remediation. The remaining liability at December 31, 2009 of $5,914 is reflected in Other Accrued Liabilities at December 31, 2009.

As of April 30, 2009, CONSOL Energy and the other participating PRPs had asserted CERCLA cost recovery and contribution claims against approximately 225 nonparticipating PRPs to recover a share of the costs incurred and to be incurred to conduct the removal actions at the Ward Site. CONSOL Energy’s portion of probable recoveries from settled claims is estimated to be $3,620. Accordingly, an asset has been included in Other Assets for these claims. We cannot predict the ultimate outcome of this Superfund site; however, it is reasonably possible that payments in the future with respect to this lawsuit may be material to the financial position, results of operations or cash flows of CONSOL Energy.

As part of conducting mining activities at the Buchanan Mine, our subsidiary, Consolidation Coal Company (“CCC”), has to remove water from the mine. Several actions have arisen with respect to the removal of naturally accumulating and pumped water from the Buchanan Mine:

Yukon Pocahontas Coal Company, Buchanan Coal Company and Sayers-Pocahontas Coal Company filed an action on March 22, 2004 against CCC which is presently pending in the Circuit Court of Buchanan County, Virginia (the “Yukon Action”). The action is related to CCC’s depositing of untreated water from its Buchanan Mine into the void spaces of nearby mines of one of our other subsidiaries, Island Creek Coal Company (“ICCC”). The plaintiffs are seeking to stop CCC from depositing any additional water in these areas, to require CCC to remove the water that is stored there along with any remaining impurities, to recover over $3,252,000 for alleged damages to the coal and gas estates and punitive damages in the amount of $350. Plaintiffs have also asserted damage claims of $150,000 against CONSOL Energy, CNX Gas Company, LLC and ICCC. The Yukon group has recently filed a demand for arbitration (the “2008 Arbitration”) against ICCC which makes similar claims relating to breach of the lease for water deposits and lost coal claims.

CCC obtained a revision to its environmental permit to deposit water from its Buchanan Mine into void spaces of VP3, and to permit the discharge of water into the nearby Levisa River under controlled conditions. Plaintiffs in the Yukon Action along with the Town of Grundy, Virginia, Buchanan County Board of Supervisors, and others have appealed the revision.

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We believe that CCC has and continues to have the right to deposit mine water from Buchanan Mine into void spaces at nearby mines. We also believe CCC was properly issued environmental permits to deposit water from the Buchanan Mine into VP3 and to discharge water into the Levisa River. CCC and the other named CONSOL Energy defendants in the Yukon Action deny all liability and intend to vigorously defend the action filed against them in connection with the removal and deposit of water from the Buchanan Mine, as well as environmental permits issued to CCC. Consequently, we have not recognized any liability related to these actions. However, if a temporary or permanent injunction were to be issued against CCC, if the environmental permits were temporarily suspended or revoked, or if damages were awarded to plaintiffs, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2006, CONSOL Energy and CCC were served with a summons in the name of the Commonwealth of Virginia with the Circuit Court of Buchanan County, Virginia regarding a special grand jury presentment in response to citizens’ complaints that noise resulting from the ventilation fan at the Buchanan Mine constitutes a public nuisance. CONSOL Energy and CCC deny that the operation of the ventilation fan is a public nuisance and intend to vigorously defend this proceeding. However, if the operation of the ventilation fan is ordered to be stopped, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In, 2007 Bluestone Coal Corporation filed a lawsuit against the Company and its subsidiary, CNX Land Resources, in the United States District Court for the Southern District of West Virginia. The suit alleges that the Company breached a contract that allegedly provides Bluestone with an option to lease coal reserves within a seven-and-one-half mile radius of Bishop, WV and seeks damages of $1,200,000. The writing relied upon only refers to a right of first refusal, rather than an option. The lawsuit has been settled. The terms of the settlement are confidential, but include CONSOL Energy granting to Bluestone the option to acquire certain mining assets and reserves. The settlement did not materially impact the financial position, results of operations or cash flows of CONSOL Energy.

South Carolina Electric & Gas Company (“SCE&G”), a utility, has demanded arbitration, seeking $36,000 in damages against CONSOL of Kentucky and CONSOL Energy Sales Company. SCE&G claims it suffered damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. The Company counterclaimed against SCE&G for $9,400 for terminating coal shipments under the sales agreement which SCE&G had agreed could be made up in 2009. A hearing on the claims is scheduled for October 11, 2010. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them. However, if damages were awarded to SCE&G, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.

In 2009, a fish kill occurred in Dunkard Creek, which is a creek with segments in both Pennsylvania and West Virginia. The fish kill was caused by the growth of golden brown algae in the creek, which appears to be an invasive species. Our subsidiary, CCC, discharges treated mine water into Dunkard Creek from its Blacksville No. 2 Mine and from its Loveridge Mine. The discharges have levels of chlorides that cause Dunkard Creek to exceed West Virginia in-stream water quality standards. Prior to the fish kill, CCC was subject to an Agreed Order with the West Virginia Department of Environmental Protection that sets forth a schedule for compliance with these in-stream chloride limits. On December 18, 2009, the West Virginia Department of Environmental Protection issued a unilateral Order that imposes additional conditions on CCC’s discharges into Dunkard Creek and requires CCC to develop a plan for long-term treatment of those and other high-chloride discharges. The Dunkard Creek fish kill is being investigated by several agencies, including the West Virginia Department of Environmental Protection, the West Virginia Department of Natural Resources, the Pennsylvania Department of Environmental Protection, and the Pennsylvania Fish and Boat Commission. The U.S. Environmental Protection Agency is also involved. We are cooperating with these investigations. We do not believe that there is a connection between the fish kill and our discharge of water into Dunkard Creek, but the investigation of the matter is continuing. If such a causal connection were established or if we are required to comply with in-stream chloride limits on an accelerated basis, it is reasonably possible that the liabilities or costs that could be incurred by CONSOL Energy in the future with respect to these matters may be material to the financial position, results of operations, or cash flows of CONSOL Energy.

In 2007, GeoMet, Inc. and certain of its affiliates filed a lawsuit against CONSOL Energy and certain of its affiliates, including CNX Gas Company LLC, in the Circuit Court for the County of Tazewell, Virginia. The lawsuit alleges, among other things, that the defendants have violated the Virginia Antitrust Act in their dealings with GeoMet in southwest Virginia. The complaint, as amended, seeks injunctive relief, compensatory damages of $385,600 and treble damages. CNX Gas continues to believe this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.

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In 2009, CNX Gas received a civil investigative demand for information and documents from the Attorney General of the Commonwealth of Virginia regarding the company’s exploration, production, transportation and sale of coalbed methane gas in Virginia. According to the request, the Attorney General is investigating whether the company may have violated the Virginia Antitrust Act. The request for information does not constitute the commencement of legal proceedings and does not make any specific allegations against the company. CNX Gas does not believe that it has violated the Virginia Antitrust Act and CNX Gas is cooperating with the Attorney General’s investigation.

The Company is a party to a case filed in 2007 captioned Earl Kennedy (and others) v. CNX Gas and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas. The complaint, as amended, seeks injunctive relief, including having CNX Gas be removed from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal that dismissal. CNX Gas believes this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.

In 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a lawsuit against CNX Gas Company LLC in the Circuit Court of the County of Buchanan for the year 2002; the county has since filed and served three substantially similar cases for years 2003, 2004 and 2005. These cases have been consolidated. The complaint alleges that CNX Gas’ calculation of the license tax on the basis of the wellhead value (sales price less post production costs) rather than the sales price is improper. For the period from 1999 through mid 2002, CNX Gas paid the tax on the basis of the sales price, but we have filed a claim for a refund for these years. Since 2002, we have continued to pay Buchanan County taxes based on our method of calculating the taxes. This litigation has been settled on terms that do not materially impact the financial position or the results of operations of CNX Gas or CONSOL Energy.

In 2007, the assigned operators, including subsidiaries of CONSOL Energy, and the Combined Fund entered into a settlement agreement that resolved all issues relating to the calculation and imposition of higher per beneficiary premium rates. The settlement agreement provides for full reimbursement of the higher per beneficiary premium rate. The settlement agreement provided for full reimbursement of higher per beneficiary premium rate previously paid by CONSOL Energy subsidiaries and related interest. In the year ended December 31, 2007, CONSOL Energy received $30,389 which was reflected as a reduction to cost of goods sold and other charges.

In 2007, production at the Buchanan Mine was suspended after several roof falls damaged some of the ventilation controls inside the mine. Production resumed in March 2008. The incident was covered under our property and business interruption insurance policy, subject to certain deductibles. Business interruption recoveries of $50,000 were recognized as Other Income in the year ended December 31, 2008, $42,000 in the coal segment and $8,000 in the gas segment.

In 2008, the Emergency Economic Stabilization Act of 2008 (the EESA Act) was signed into law. The EESA Act contained a section that authorizes certain coal producers and exporters who had filed a Black Lung Excise Tax (BLET) return on or after October 1, 1990, to request a refund of the BLET paid on export sales during these years. The EESA Act requires that the U.S. Treasury refund a coal producer or exporter an amount equal to the BLET erroneously paid on export sales in prior years along with interest computed at the statutory rates applicable to overpayments. In the year ended December 31, 2008, CONSOL Energy recognized a receivable related to these refunds of $58,983, including interest of $32,444. In relation to this receivable, CONSOL Energy recognized a payable of $3,187 that was owed to third parties upon collection of the refunds. The receivable was collected and the related payables were paid in the year ended December 31, 2009.

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At December 31, 2009, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credits are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.

	Amount and Duration of Commitments
	Total Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Letters of Credit:
Employee-Related	$	193,017	$	193,017	$	—	$	—	$	—
Environmental		63,502		63,502		—		—		—
Gas		14,913		14,913		—		—		—
Other		11,914		11,850		64		—		—
Total Letters of Credit		283,346		283,282		64		—		—
Surety Bonds:
Employee-Related		193,251		193,251		—		—		—
Environmental		345,955		345,782		173		—		—
Gas		4,442		4,442		—		—		—
Other		9,726		9,713		13		—		—
Total Surety Bonds		553,374		553,188		186		—		—
Guarantees:
Coal		111,088		79,890		25,198		1,000		5,000
Gas		56,156		30,479		22,577		—		3,100
Other		277,694		42,925		71,617		51,991		111,161
Total Guarantees		444,938		153,294		119,392		52,991		119,261
Total Commitments	$	1,281,658	$	989,764	$	119,642	$	52,991	$	119,261

CONSOL Energy and CNX Gas enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheets. As of December 31, 2009, the purchase obligations for each of the next five years were as follows:

Obligations Due	Amount
Less than 1 year	$	69,228
1 – 3 years		55,680
3 – 5 years		49,934
More than 5 years		303,347
Total Purchase Obligations	$	478,189

Costs related to major equipment purchases under these purchase obligations was $89,261, $10,957 and $15,886 for the years ended December 31, 2009, 2008 and 2007. Firm transportation expense under these purchase obligations was $21,668, $11,476 and $9,390 for the years ended December 31, 2009, 2008 and 2007 respectively. Expenses related to gas drilling purchase obligations were $585 for the year ended December 31, 2009. Expenses related to other operating goods and services under these purchase obligations was $120 and $60 for the years ended December 31, 2009 and 2008.

Employee-related financial guarantees have primarily been provided to support the United Mine Workers’ of America’s 1992 Benefit Plan and various state workers’ compensation self-insurance programs. Environmental financial guarantees have primarily been provided to support various performance bonds related to reclamation and other environmental issues. Gas financial guarantees have primarily been provided to support various performance bonds related to land usage and restorative issues. Other guarantees have been extended to support insurance policies, legal matters and various other items necessary in the normal course of business. Other guarantees have also been provided to promise the full and timely payments to lessors of mining equipment and support various other items necessary in the normal course of business.

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Note 25—Segment Information:

CONSOL Energy has two principal business units: Coal and Gas. The principal activities of the Coal unit are mining, preparation and marketing of steam coal, sold primarily to power generators and metallurgical coal, sold to metal and coke producers. The Coal unit includes three reportable segments. These reportable segments are Steam, Low 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, 2009, the Steam aggregated segment includes the following mines or type of coal sold: Bailey, Blacksville #2, Buchanan steam, Emery, Enlow Fork, Fola Complex, Jones Fork Complex, Loveridge, McElroy, Miller Creek Complex, Mine 84, Robinson Run and Shoemaker. For the year ended December 31, 2009, the Low Volatile Metallurgical aggregated segment includes the Buchanan metallurgical sales and the Amonate Complex. The Other Coal segment includes our purchased coal activities, idled mine activities, as well as various other activities assigned to the coal segment but not allocated to each individual mine or type of coal sold. The principal activity of the Gas unit is to produce pipeline quality methane gas for sale primarily to gas wholesalers. The Gas unit includes four reportable segments. These reportable segments are Coalbed Methane, Marcellus, Conventional and Other Gas. For the years ended December 31, 2008 and 2007, the Marcellus and Conventional segments were insignificant to the Gas unit with sales representing less than 1% of total sales volumes. The Other Gas segment includes our purchased gas activities as well as various other activities assigned to the gas segment 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, including rentals of buildings and flight operations. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Certain reclassifications of 2008 and 2007 segment information have been made to conform to the 2009 presentation. These reclassifications include changes to the coal operating segments and the addition of the Gas operating segments. Because the Marcellus and Conventional segments are insignificant in the years ended December 31, 2008 and 2007, 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, 2009 are:

	Steam		Low Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Conventional Gas			Other Gas			Total Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales - outside	$	3,122,226	$	248,543	$	39,117		$	3,409,886	$	594,668	$	21,006	$	9,005		$	4,250		$	628,929	$	272,976	$	—		$	4,311,791	(A	)
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	$	3,122,226	$	248,543	$	188,024		$	3,558,793	$	594,668	$	21,006	$	9,005		$	53,912		$	678,591	$	425,351	$	(154,046	)	$	4,508,689
Earnings (Loss) Before Income Taxes	$	800,435	$	93,631	$	(336,316	)	$	557,750	$	301,113	$	3,940	$	(1,161	)	$	(42,057	)	$	261,835	$	6,278	$	(37,518	)	$	788,345	(B	)
Segment assets								$	4,672,508											$	2,171,495	$	317,004	$	564,394		$	7,725,401	(C	)
Depreciation, depletion and amortization								$	310,346											$	107,251	$	19,820	$	—		$	437,417
Capital expenditures								$	580,401											$	322,126	$	17,553	$	—		$	920,080

(A) There were no sales to customers aggregating over 10% of total revenue in 2009.

(B) Includes equity in earnings of unconsolidated affiliates of $5,663, $637 and $9,408 for Coal, Gas and All Other, respectively.

(C) Includes investments in unconsolidated equity affiliates of $12,569, $24,590 and $46,374 for Coal, Gas and All Other, respectively.

102

Industry segment results for the year ended December 31, 2008 are:

	Steam		Low 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	(D	)
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	$	(167,198	)	$	363,159	$	400,330	$	—	$	—	$	(14,376	)	$	385,954	$	15,726	$	(39,244	)	$	725,595	(E	)
Segment assets								$	4,387,584										$	2,094,748	$	322,137	$	565,989		$	7,370,458	(F	)
Depreciation, depletion and amortization								$	299,831										$	70,010	$	19,780	$	—		$	389,621
Capital expenditures								$	445,594										$	560,663	$	55,412	$	—		$	1,061,669

(D) There were no sales to customers aggregating over 10% of total revenue in 2008.

(E) Includes equity in earnings of unconsolidated affiliates of $2,534, $551 and $8,055 for Coal, Gas and All Other, respectively.

(F) Includes investments in unconsolidated equity affiliates of $9,386, $25,204 and $38,406 for Coal, Gas and All Other, respectively. Also, included in the Coal segment is $58,983 of receivables related to the Emergency Economic Stabilization Act of 2008.

103

Industry segment results for the year ended December 31, 2007 are:

	Steam		Low Volatile Metallurgical		Other Coal			Total Coal		Coalbed Methane		Marcellus Shale		Conventional Gas		Other Gas			Total Gas		All Other		Corporate, Adjustments & Eliminations			Consolidated
Sales - outside	$	2,422,515	$	217,889	$	38,277		$	2,678,681	$	410,211	$	—	$	—	$	—		$	410,211	$	235,454	$	—		$	3,324,346	(G	)
Sales - Purchased Gas		—		—		—			—		—		—		—		7,628			7,628		—		—			7,628
Sales - Gas Royalty Interests		—		—		—			—		—		—		—		46,586			46,586		—		—			46,586
Freight - outside		—		—		186,909			186,909		—		—		—		—			—		—		—			186,909
Intersegment transfers		—		—		—			—		—		—		—		6,242			6,242		129,648		(135,890	)		—
Total Sales and Freight	$	2,422,515	$	217,889	$	225,186		$	2,865,590	$	410,211	$	—	$	—	$	60,456		$	470,667	$	365,102	$	(135,890	)	$	3,565,469
Earnings (Loss) Before Income Taxes	$	447,104	$	69,602	$	(284,087	)	$	232,619	$	218,067	$	—	$	—	$	(3,193	)	$	214,874	$	12,287	$	(30,823	)	$	428,957	(H	)
Segment assets								$	4,039,513										$	1,378,709	$	253,792	$	536,076		$	6,208,090	(I	)
Depreciation, depletion and amortization								$	257,349										$	48,961	$	18,405	$	—		$	324,715
Capital expenditures								$	681,408										$	304,088	$	54,342	$	—		$	1,039,838

(G) There were no sales to customers aggregating over 10% of total revenue in 2007.

(H) Includes equity in earnings of unconsolidated affiliates of $1,027, $2,174 and $3,350 for Coal, Gas and All Other, respectively.

(I) Includes investments in unconsolidated equity affiliates of $3,101, $56,865 and $34,900 for Coal, Gas and All Other, respectively.

104

Reconciliation of Segment Information to Consolidated Amounts:

Revenue and Other Income:

	For the Years Ended December 31,
	2009		2008		2007
Total segment sales and freight from external customers	$	4,508,689	$	4,486,303	$	3,565,469
Other income not allocated to segments (Note 3)		113,186		166,142		196,728
Total Consolidated Revenue and Other Income	$	4,621,875	$	4,652,445	$	3,762,197

Earnings Before Income Taxes:

Segment Earnings Before Income Taxes for total reportable business segments	$	819,585		$	749,113		$	447,493
Segment Earnings Before Income Taxes for all other businesses		6,278			15,726			12,287
Interest income (expense), net and other non-operating activity (J)		(26,472	)		(39,244	)		(30,823	)
Corporate restructuring (J)		(4,378	)		—			—
Lease settlement (J)		(6,668	)		—			—
Earnings Before Income Taxes	$	788,345		$	725,595		$	428,957

Total Assets:

	December 31,
	2009		2008		2007
Segment assets for total reportable business segments	$	6,844,003	$	6,482,332	$	5,418,222
Segment assets for all other businesses		317,004		322,137		253,792
Items excluded from segment assets:
Cash and other investments (J)		65,025		136,951		9,978
Deferred tax assets		498,680		394,142		505,631
Recoverable income taxes		—		33,862		19,090
Bond issuance costs		689		1,034		1,377
Total Consolidated Assets	$	7,725,401	$	7,370,458	$	6,208,090

(J) Excludes amounts specifically related to the gas segment.

105

Enterprise-Wide Disclosures:

CONSOL Energy’s Revenues by geographical location:

	For the Years Ended December 31,
	2009		2008		2007
United States	$	4,026,619	$	3,841,665	$	3,077,573
Europe		298,262		462,291		332,280
South America		120,174		94,230		40,255
Canada		25,056		88,106		115,361
Other		38,578		11		—
Total Revenues and Freight from External Customers (K)	$	4,508,689	$	4,486,303	$	3,565,469

(K) CONSOL Energy attributes revenue to individual countries based on the location of the customer.

CONSOL Energy’s Property, Plant and Equipment by geographical location are:

	December 31,
	2009		2008
United States	$	6,090,703	$	5,732,021
Canada		33,587		33,828
Belgium		—		123
	$	6,124,290	$	5,765,972

106

Note 26—Guarantor Subsidiaries Financial Information:

The payment obligations under the $250,000, 7.875 percent per annum notes due March 1, 2012 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by several subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (“SEC”), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, an 83.3% owned guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. CNX Gas is presented in a separate column in accordance with SEC Regulation S-X Rule 3-10. CNX Gas Corporation is a reporting company under Section 12(b) of the Securities Exchange Act of 1933, and as such, CNX Gas Corporation files its own financial statements with the Securities and Exchange Commission and those financial statements, when filed, are publicly available on Edgar. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other 100% owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.

Income Statement for the Year Ended December 31, 2009:

	Parent			CNX Gas Guarantor		Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	630,598	$	3,487,022		$	197,350	$	(3,179	)	$	4,311,791
Sales—Purchased gas		—			7,040		—			—		—			7,040
Sales—Gas Royalty Interest		—			40,951		—			—		—			40,951
Freight—Outside		—			—		148,907			—		—			148,907
Other Income (including equity earnings)		622,216			4,855		76,442			22,173		(612,500	)		113,186
Total Revenue and Other Income		622,216			683,444		3,712,371			219,523		(615,679	)		4,621,875
Cost of Goods Sold and Other Operating Charges		84,960			155,583		2,083,462			190,854		242,193			2,757,052
Purchased Gas Costs		—			6,442		—			—		—			6,442
Gas Royalty Interest		—			32,423		—			—		(47	)		32,376
Related Party Activity		7,052			—		132,106			1,495		(140,653	)		—
Freight Expense		—			—		148,907			—		—			148,907
Selling, General and Administrative Expense		—			99,526		118,287			1,287		(88,396	)		130,704
Depreciation, Depletion and Amortization		13,022			107,251		316,352			2,654		(1,862	)		437,417
Interest Expense		13,229			7,568		10,959			15		(352	)		31,419
Taxes Other Than Income		9,576			12,590		265,180			2,595		—			289,941
Black Lung Excise Tax Refund		—			—		(728	)		—		—			(728	)
Total Costs		127,839			421,383		3,074,525			198,900		10,883			3,833,530
Earnings (Loss) Before Income Taxes		494,377			262,061		637,846			20,623		(626,562	)		788,345
Income Taxes (Benefit)		(45,340	)		98,636		160,105			7,802		—			221,203
Net Income		539,717			163,425		477,741			12,821		(626,562	)		567,142
Less: Net Income Attributable to Noncontrolling Interest		—			1,037		(1,037	)		—		(27,425	)		(27,425	)
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	539,717		$	164,462	$	476,704		$	12,821	$	(653,987	)	$	539,717

107

Balance Sheet for December 31, 2009:

	Parent		CNX Gas Guarantor			Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	59,549	$	1,124		$	3,764		$	1,170	$	—		$	65,607
Accounts and Notes Receivable:
Trade		—		43,421			113			273,926		—			317,460
Other		4,781		975			3,281			6,946		—			15,983
Inventories		—		—			262,755			44,842		—			307,597
Deferred Income Taxes		108,254		(34,871	)		—			—		—			73,383
Prepaid Expenses		18,979		103,094			36,767			2,166		—			161,006
Total Current Assets		191,563		113,743			306,680			329,050		—			941,036
Property, Plant and Equipment:
Property, Plant and Equipment		162,145		2,409,751			8,082,159			27,900		—			10,681,955
Less-Accumulated Depreciation, Depletion and Amortization		82,733		433,201			4,022,295			19,436		—			4,557,665
Property, Plant and Equipment—Net		79,412		1,976,550			4,059,864			8,464		—			6,124,290
Other Assets:
Deferred Income Taxes		759,790		(334,493	)		—			—		—			425,297
Investment in Affiliates		4,399,823		24,591			797,269			3,921		(5,142,071	)		83,533
Other		84,736		21,627			33,216			11,666		—			151,245
Total Other Assets		5,244,349		(288,275	)		830,485			15,587		(5,142,071	)		660,075
Total Assets	$	5,515,324	$	1,802,018		$	5,197,029		$	353,101	$	(5,142,071	)	$	7,725,401
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	93,876	$	53,516		$	114,872		$	7,296	$	—		$	269,560
Accounts Payable (Recoverable)-Related Parties		2,117,616		5,171			(2,378,119	)		255,332		—			—
Short-Term Notes Payable		415,000		57,850			—			—		—			472,850
Current Portion of Long-Term Debt		501		8,616			35,853			424		—			45,394
Accrued Income Taxes		27,944		31,765			(31,765	)		—		—			27,944
Other Accrued Liabilities		546,066		25,455			34,569			6,748		—			612,838
Total Current Liabilities		3,201,003		182,373			(2,224,590	)		269,800		—			1,428,586
Long-Term Debt:		250,255		65,690			106,369			594		—			422,908
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions		—		3,642			2,675,704			—		—			2,679,346
Pneumoconiosis		—		—			184,965			—		—			184,965
Mine Closing		—		—			397,320			—		—			397,320
Gas Well Closing		—		8,312			77,680			—		—			85,992
Workers’ Compensation		—		—			152,486			—		—			152,486
Deferred Revenue		—		—			—			—		—			—
Salary Retirement		189,697		—			—			—		—			189,697
Reclamation		—		—			27,105			—		—			27,105
Other		88,821		35,101			8,595			—		—			132,517
Total Deferred Credits and Other Liabilities		278,518		47,055			3,523,855			—		—			3,849,428
Consol Energy Inc. Stockholders’ Equity		1,785,548		1,511,270			3,787,025			82,707		(5,381,002	)		1,785,548
Noncontrolling Interest		—		(4,370	)		4,370			—		238,931			238,931
Total Liabilities and Stockholders’ Equity	$	5,515,324	$	1,802,018		$	5,197,029		$	353,101	$	(5,142,071	)	$	7,725,401

108

Condensed Statement of Cash Flows

For the Year Ended December 31, 2009:

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non-Guarantors			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	64,095		$	360,163		$	523,596		$	(2,403	)	$	—	$	45,451
Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(336,447	)	$	(583,633	)	$	—		$	—	$	(920,080	)
Investment in Equity Affiliates		—			1,250			3,605			—			—		4,855
Proceeds from Sale of Assets		—			288			69,596			—			—		69,884
Net Cash Used in Investing Activities	$	—		$	(334,909	)	$	(510,432	)	$	—		$	—	$	(845,341	)
Cash Flows from Financial Activities:
Dividends Paid	$	(72,292	)	$	—		$	—		$	—		$	—	$	(72,292	)
Proceeds from Revolver		(70,000	)		(14,850	)		—			—			—		(84,850	)
Other Financing Activities		5,275			(11,206	)		(9,481	)		(461	)		—		(15,873	)
Net Cash Provided By (Used in) Financing Activities	$	(137,017	)	$	(26,056	)	$	(9,481	)	$	(461	)	$	—	$	(173,015	)

Income Statement for the Year Ended December 31, 2008:

	Parent			CNX Gas Guarantor		Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	688,325	$	3,231,163		$	271,613	$	(9,532	)	$	4,181,569
Sales—Purchased gas		—			8,464		—			—		—			8,464
Sales—Gas Royalty Interest		—			79,302		—			—		—			79,302
Freight—Outside		—			—		216,968			—		—			216,968
Other Income (including equity earnings)		513,910			13,330		117,487			38,375		(516,960	)		166,142
Total Revenue and Other Income		513,910			789,421		3,565,618			309,988		(526,492	)		4,652,445
Cost of Goods Sold and Other Operating Charges		72,790			132,254		2,312,477			112,402		213,280			2,843,203
Purchased Gas Costs		—			8,175		—			—		—			8,175
Gas Royalty Interest		—			74,041		—			—		(79	)		73,962
Related Party Activity		5,622			—		39,325			155,304		(200,251	)		—
Freight Expense		—			—		216,968			—		—			216,968
Selling, General and Administrative Expense		—			80,246		39,660			4,637		—			124,543
Depreciation, Depletion and Amortization		9,382			70,010		300,635			11,485		(1,891	)		389,621
Interest Expense		17,888			7,820		10,312			498		(335	)		36,183
Taxes Other Than Income		5,887			24,146		250,398			9,559		—			289,990
Black Lung Excise Tax Refund		—			—		(55,795	)		—		—			(55,795	)
Total Costs		111,569			396,692		3,113,980			293,885		10,724			3,926,850
Earnings (Loss) Before Income Taxes		402,341			392,729		451,638			16,103		(537,216	)		725,595
Income Taxes (Benefit)		(40,129	)		153,656		120,315			6,092		—			239,934
Net Income		442,470			239,073		331,323			10,011		(537,216	)		485,661
Less: Net Income Attributable to Noncontrolling Interest		—			—		—			—		(43,191	)		(43,191	)
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	442,470		$	239,073	$	331,323		$	10,011	$	(580,407	)	$	442,470

109

Balance Sheet for December 31, 2008:

	Parent		CNX Gas Guarantor			Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Assets:
Current Assets:
Cash and Cash Equivalents	$	132,471	$	1,926		$	81		$	4,034	$	—		$	138,512
Accounts and Notes Receivable:
Trade		—		61,764			35			159,930		—			221,729
Other		1,767		3,080			68,910			5,795		—			79,552
Inventories		—					184,140			43,670		—			227,810
Recoverable Income Taxes		3,560		30,302			—								33,862
Deferred Income Taxes		115,599		(55,000	)		—			—		—			60,599
Prepaid Expenses		23,612		152,786			40,409			4,943		—			221,750
Total Current Assets		277,009		194,858			293,575			218,372		—			983,814
Property, Plant and Equipment:
Property, Plant and Equipment		175,027		2,113,570			7,606,735			84,956		—			9,980,288
Less-Accumulated Depreciation, Depletion and Amortization		71,781		322,470			3,793,378			26,687		—			4,214,316
Property, Plant and Equipment—Net		103,246		1,791,100			3,813,357			58,269		—			5,765,972
Other Assets:
Deferred Income Taxes		664,881		(331,338	)		—			—		—			333,543
Investment in Affiliates		3,734,125		25,204			930,708			1,102		(4,618,143	)		72,996
Other		77,253		58,811			34,521			43,548		—			214,133
Total Other Assets		4,476,259		(247,323	)		965,229			44,650		(4,618,143	)		620,672
Total Assets	$	4,856,514	$	1,738,635		$	5,072,161		$	321,291	$	(4,618,143	)	$	7,370,458
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts Payable	$	87,734	$	100,565		$	159,677		$	37,221	$	—		$	385,197
Accounts Payable (Recoverable)- Related Parties		1,853,629		2,234			(1,992,924	)		137,061		—			—
Short-Term Notes Payable		485,000		72,700			—			—		—			557,700
Current Portion of Long-Term Debt		1,473		8,462			12,093			373		—			22,401
Other Accrued Liabilities		410,086		42,089			84,417			9,850		—			546,442
Total Current Liabilities		2,837,922		226,050			(1,736,737	)		184,505		—			1,511,740
Long-Term Debt:		252,145		74,682			140,956			568		—			468,351
Deferred Credits and Other Liabilities:
Postretirement Benefits Other Than Pensions		—		2,728			2,490,616			—		—			2,493,344
Pneumoconiosis		—		—			190,261			—		—			190,261
Mine Closing		—		—			393,112			11,517		—			404,629
Gas Well Closing		—		7,401			73,153			—		—			80,554
Workers’ Compensation		—		—			128,477			—		—			128,477
Salary Retirement		194,567		—			—			—		—			194,567
Reclamation		—		—			15,363			22,830		—			38,193
Other		109,693		42,900			7,698			25,705		—			185,996
Total Deferred Credits and Other Liabilities		304,260		53,029			3,298,680			60,052		—			3,716,021
CONSOL Energy Inc. Stockholders’ Equity		1,462,187		1,384,874			3,370,895			74,533		(4,830,302	)		1,462,187
Noncontrolling Interest		—		—			—			—		212,159			212,159
Total Liabilities and Stockholders’ Equity	$	4,856,514	$	1,738,635		$	5,073,794		$	319,658	$	(4,618,143	)	$	7,370,458

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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	$	34,647		$	447,375		$	510,475		$	36,967		$	—	$	1,029,464
Cash Flows from Investing
Capital Expenditures	$	(11,371	)	$	(560,663	)	$	(464,603	)	$	(25,032	)	$	—	$	(1,061,669	)
Investment in Equity Affiliates		—			1,081			798			—			—		1,879
Purchase of Stock in Subsidiary								(67,259	)							(67,259	)
Proceeds from Sale of Assets		—			450			27,743			—			—		28,193
Net Cash Used in Investing Activities	$	(11,371	)	$	(559,132	)	$	(503,321	)	$	(25,032	)	$	—	$	(1,098,856	)
Cash Flows from Financial Activities:
Dividends Paid	$	(72,957	)	$	—		$	—		$	—		$	—	$	(72,957	)
Proceeds from Revolver		237,500			72,700			—			—			—		310,200
Purchase of Treasury Stock		(97,794	)		—			—			—			—		(97,794	)
Other Financing Activities		37,218			8,935			(8,364	)		(10,985	)		—		26,804
Net Cash Provided By (Used in) Financing Activities	$	103,967		$	81,635		$	(8,364	)	$	(10,985	)	$	—	$	166,253

Income Statement for the Year Ended December 31, 2007:

	Parent			CNX Gas Guarantor		Other Subsidiary Guarantors			Non-Guarantors		Elimination			Consolidated
Sales—Outside	$	—		$	416,453	$	2,718,493		$	201,018	$	(11,618	)	$	3,324,346
Sales—Purchased gas		—			7,628		—			—		—			7,628
Sales—Gas Royalty Interest		—			46,586		—			—		—			46,586
Freight—Outside		—			—		186,909			—		—			186,909
Other Income (including equity earnings)		333,581			8,815		141,735			40,093		(327,496	)		196,728
Total Revenue and Other Income		333,581			479,482		3,047,137			241,111		(339,114	)		3,762,197
Cost of Goods Sold and Other Operating Charges		63,899			102,278		1,916,159			61,864		207,800			2,352,000
Purchased Gas Costs		—			7,162		—			—		—			7,162
Gas Royalty Interest		—			40,011		—			—		(90	)		39,921
Related Party Activity		(4,601	)		—		87,459			134,213		(217,071	)		—
Freight Expense		—			—		186,909			—		—			186,909
Selling, General and Administrative Expense		—			54,825		51,029			2,810		—			108,664
Depreciation, Depletion and Amortization		7,666			48,961		259,825			10,343		(2,080	)		324,715
Interest Expense		24,932			5,606		(250	)		563		—			30,851
Taxes Other Than Income		5,790			—		246,177			6,959		—			258,926
Black Lung Excise Tax Refund		—			—		24,092			—		—			24,092
Total Costs		97,686			258,843		2,771,400			216,752		(11,441	)		3,333,240
Earnings (Loss) Before Income Taxes		235,895			220,639		275,737			24,359		(327,673	)		428,957
Income Taxes (Benefit)		(31,887	)		84,961		73,848			9,215		—			136,137
Net Income		267,782			135,678		201,889			15,144		(327,673	)		292,820
Less: Net Income Attributable to Noncontrolling Interest		—			—		—			—		(25,038	)		(25,038	)
Net Income Attributable to CONSOL Energy Inc. Shareholders	$	267,782		$	135,678	$	201,889		$	15,144	$	(352,711	)	$	267,782

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Condensed Statement of Cash Flows

For the Year Ended December 31, 2007:

	Parent			CNX Gas Guarantor			Other Subsidiary Guarantors			Non-Guarantors			Elimination		Consolidated
Net Cash Provided by Operating Activities	$	(258,800	)	$	272,448		$	649,136		$	21,249		$	—	$	684,033
Cash Flows from Investing Activities:
Capital Expenditures	$	—		$	(348,631	)	$	(372,424	)	$	(22,059	)	$	—	$	(743,114	)
Acquisition of AMVEST		—			—			(296,724	)		—			—		(296,724	)
Investment in Equity Affiliates		—			(5,783	)		(1,274	)		—			—		(7,057	)
Purchase of Stock in Subsidiary		—			—			(10,000	)		—			—		(10,000	)
Proceeds from Sale of Assets		—			187			83,754			850			—		84,791
Net Cash Used in Investing Activities	$	—		$	(354,227	)	$	(596,668	)	$	(21,209	)	$	—	$	(972,104	)
Cash Flows from Financial Activities:
Dividends Paid	$	(56,475	)	$	—		$	—		$	—		$	—	$	(56,475	)
Proceeds from Revolver		247,500			—			—			—			—		247,500
Purchase of Treasury Stock		(80,157	)		—			—			—			—		(80,157	)
Payments on Long Term Notes		—			—			(45,000	)		—			—		(45,000	)
Other Financing Activities		42,906			6,654			(7,589	)		(2,000	)		—		39,971
Net Cash Provided By (Used in) Financing Activities	$	153,774		$	6,654		$	(52,589	)	$	(2,000	)	$	—	$	105,839

Supplemental Coal Data (unaudited):

	Millions of Tons For the Year Ended December 31,
	2009		2008		2007		2006		2005
Proved and probable reserves at beginning of period	4,543		4,526		4,272		4,546		4,509
Purchased reserves	5		—		177		3		56
Reserves sold in place	(3	)	(12	)	(33	)	(2	)	(2	)
Production	(59	)	(65	)	(65	)	(67	)	(69	)
Revisions and other changes	34		94		175		(208	)	52
Consolidated proved and probable reserves at end of period*	4,520		4,543		4,526		4,272		4,546
Proportionate share of proved and probable reserves of unconsolidated equity affiliates*	170		171		179		—		—

* Proved and probable coal reserves are the equivalent of “demonstrated reserves” under the coal resource classification system of the U.S. Geological Survey. Generally, these reserves would be commercially mineable at year-end prices and cost levels, using current technology and mining practices.

CONSOL Energy’s coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2009, 898 million tons were assigned to mines either in production, temporarily idle, or under development. The proved and probable reserves at December 31, 2009 include 3,960 million tons of steam coal reserves, of which approximately 8 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million British thermal unit (Btu), and an additional 14 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. The reserves also include 560 million tons of metallurgical coal in consolidated reserves, of which approximately 62 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu, and an additional 37 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. A significant portion of this metallurgical coal can also serve the steam coal market.

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Other Supplemental Information—Supplemental Gas Data (unaudited)

The following information was prepared in accordance with the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).”

Capitalized Costs:

	As of December 31,
	2009			2008
Proved properties	$	152,010		$	121,605
Unproved properties		271,553			220,848
Wells and related equipment		1,171,146			1,019,880
Gathering assets		804,212			740,396
Total Property, Plant and Equipment		2,398,921			2,102,729
Accumulated Depreciation, Depletion and Amortization		(429,966	)		(319,959	)
Net Capitalized Costs	$	1,968,955		$	1,782,770

Costs incurred for property acquisition, exploration and development (*):

	For the Years Ended December 31,
	2009		2008		2007
Property acquisitions and other changes
Proved properties	$	30,405	$	17,090	$	33,205
Unproved properties		50,705		119,168		80,313
Development		181,944		378,119		257,935
Exploration		46,023		68,495		16,503
Total	$	309,077	$	582,872	$	387,956

(*) Includes costs incurred whether capitalized or expensed.

Results of Operations for Producing Activities:

	For the Twelve Months Ended December 31,
	2009				2008				2007
	Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates
Production Revenue	$	630,598	$	—	$	688,325	$	—	$	416,452	$	2,755
Royalty Interest Gas Revenue		40,951		—		79,302		—		46,586		294
Purchased Gas Revenue		7,040		—		8,464		—		7,628		201
Total Revenue		678,589		—		776,091		—		470,666		3,250
Lifting Costs		55,285		—		67,653		—		38,721		679
Gathering Costs		95,687		—		83,752		—		61,798		630
Royalty Interest Gas Costs		32,423		—		74,041		—		40,011		294
Other Costs		45,795		—		34,078		—		19,772		646
Purchased Gas Costs		6,442		—		8,175		—		7,162		165
DD&A		107,251		—		70,010		—		48,961		294
Total Costs		342,883		—		337,709		—		216,425		2,708
Pre-tax Operating Income		335,706		—		438,382		—		254,241		542
Income Taxes		125,890		—		171,407		—		98,595		210
Results of Operations for Producing Activities excluding Corporate and Interest Costs	$	209,816	$	—	$	266,975	$	—	$	155,646	$	332

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The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:

	For the Years Ended December 31,
	2009		2008		2007
Production in million cubic feet		94,415		76,562		58,249
Average gas sales price before effects of financial settlements (per thousand cubic feet)	$	4.15	$	8.99	$	6.87
Average effects of financial settlements (per thousand cubic feet)	$	2.53	$	—	$	0.33
Average gas sales price including effects of financial settlements (per thousand cubic feet)	$	6.68	$	8.99	$	7.20
Average lifting costs, excluding ad valorem and severance taxes (per thousand cubic feet)	$	0.48	$	0.58	$	0.39

During the years ended December 31, 2009, 2008 and 2007, we drilled 247, 534 and 370 net development wells, respectively. Of these wells drilled in the year ended December 31, 2009 there was one dry well. There were no dry wells in the years ended December 31, 2008 and 2007.

During the years ended December 31, 2009, 2008 and 2007, we drilled 18, 56 and 9 net exploratory wells, respectively. Of the wells drilled in the years ended December 31, 2009 and 2008, there were one and three dry wells, respectively. There were no dry wells in the year ended December 31, 2007.

At December 31, 2009, there were six development wells in the process of being drilled. Drilling activities are currently in progress to complete the drilling of these wells by the end of March 2010.

At December 31, 2009, there were ten exploratory wells in the process of being drilled. Drilling and evaluation activities will be in process throughout the 2010 period.

CNX Gas is committed to provide 44.1 Bcf of gas under existing contracts or agreements over the course of the next two years. CNX Gas expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.

Most of our development wells and proved acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied. The following table sets forth the number of CNX Gas producing wells, developed acreage and undeveloped acreage at December 31, 2009:

	Gross	Net(1)
Producing Wells (including gob wells)	5,240	3,926
Proved Developed Acreage	260,327	254,753
Proved Undeveloped Acreage	56,090	54,298
Unproved Acreage	3,957,174	3,399,490
Total Acreage	4,273,591	3,708,541

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

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Proved Oil and Gas Reserve Quantities:

The preparation of our gas reserve estimates are completed in accordance with CNX Gas’ prescribed internal control procedures, which include verification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer. Our 2009 gas reserve results were audited by Netherland, Sewell and Associates, Inc. The technical person primarily responsible for overseeing the audit of our reserves is a certified petroleum engineer. The gas reserve estimates are as follows:

	2009		2008				2007
	Consolidated Operations		Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates
Net Reserve Quantity (MMcfe)
Beginning reserves	1,422,046		1,339,909		3,584		1,263,293		2,200
Revisions(b)	177,004		(30,828	)	—		(25,036	)	221
Extensions and discoveries(c)	406,756		182,701		—		145,834		1,484
Production	(94,415	)	(76,562	)	—		(57,928	)	(321	)
Acquisition of remaining interest in equity affiliate	—		3,584		(3,584	)	—		—
Purchases of reserves in-place	—		3,242		—		13,746		—
Sale of reserves in-place	—		—		—		—		—
Ending reserves(a)	1,911,391		1,422,046		—		1,339,909		3,584

(a) Proved developed and proved undeveloped gas reserves are defined by the Securities and Exchange Commission (SEC) Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX Gas cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas and coalbed methane gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.

(b) Revisions are primarily due to efficiencies in operations which resulted in a reduction of operating costs, a comprehensive look into reservoir characterization and well performance.

(c) Extensions and discoveries are due to the addition of our Marcellus Shale acreage and approvals from the Oil & Gas Board in Virginia to drill and complete wells on tighter spacing. Extensions and discoveries also include 120,933 MMcfe as a result of initially applying the amendments of ASC 932 in ASU 2010-03 related to capturing proved undeveloped locations more than one location away if reliable technology can be demonstrated.

	2009			2008			2007
	All Products	Natural Gas mmcf	Oil mmcfe	All Products	Natural Gas mmcf	Oil mmcfe	All Products	Natural Gas mmcf	Oil mmcfe
Proved developed reserves (consolidated entities only)
Beginning of year	783,290	783,010	280	667,726	667,443	283	609,700	609,538	162
End of year	1,040,257	1,039,052	1,205	783,290	783,010	280	667,726	667,443	283
Proved undeveloped reserves (consolidated entities only)
Beginning of year	638,756	638,756	—	672,183	672,183	—	653,593	653,593	—
End of year	871,134	871,134	—	638,756	638,756	—	672,183	672,183	—

	For the Year Ended December 31, 2009
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves	638,756
Undeveloped reserves transferred to developed(a)	(118,145	)
Revisions	27,601
Extension and discoveries	322,922
Ending proved undeveloped reserves(b)	871,134

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(a) During 2009, various exploration and development drilling and evaluations were completed. Approximately, $45,326 of capital was spent in the year ended December 31, 2009 related to undeveloped reserves that were transferred to developed.

(b) Included in proved undeveloped reserves at December 31, 2009 are approximately 120,000 MMcfe of reserves that have been reported for more than five years that relate specifically to CONSOL Energy’s Buchanan Mine. These undeveloped reserves will be developed in order to de-gas the mine ahead of longwall mining.

The following table represents the capitalized exploratory well cost activity as indicated:

	December 31, 2009
Costs pending the determination of proved reserves at December 31, 2009(a)
Less than one year	$	156
More than one year but less than five years		5,454
More than five years		2,627
Total	$	8,237

(a) Costs held in exploratory for more than one year represent exploration wells away from existing infrastructure. The additional planned exploration expenditures will allow us to invest in infrastructure to support these fields.

	For the Years Ended December 31,
	2009		2008		2007
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves	$	52,332	$	1,887	$	402
Costs expensed due to determination of dry hole or abandonment of project	$	8,194	$	1,197	$	—

CNX Gas’ proved gas reserves are located in the United States.

Standardized Measure of Discounted Future Net Cash Flows:

The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year ended December 31, 2009. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CNX Gas. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CNX Gas’ investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a different price and cost assumptions.

The standardized measure is intended to provide a better means for comparing the value of CNX Gas’ proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.

	December 31,
	2009			2008			2007
Future Cash Flows:
Revenues	$	7,975,195		$	8,856,817		$	9,509,665
Production costs		(3,123,532	)		(3,525,902	)		(3,004,619	)
Development costs		(995,569	)		(793,592	)		(636,436	)
Income tax expense		(1,465,075	)		(1,713,713	)		(2,259,415	)
Future Net Cash Flows		2,391,019			2,823,610			3,609,195
Discounted to present value at a 10% annual rate		(1,496,668	)		(1,605,176	)		(2,219,655	)
Total standardized measure of discounted net cash flows(a)	$	894,351		$	1,218,434		$	1,389,540

(a) The estimated effect on the PV-10 calculation of initially applying the amendments of ASC 932 in ASU 2010-03 was $39,059.

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The following are the principal sources of change in the standardized measure of discounted future net cash flows during:

	December 31,
	2009			2008						2007
	Consolidated Operations			Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates
Balance at beginning of period	$	1,218,434		$	1,384,983		$	4,557		$	933,186		$	1,705
Net changes in sales prices and production costs		(333,130	)		(676,358	)		—			1,681,550			7,356
Sales net of production costs		(335,706	)		(438,382	)		—			(207,688	)		(1,122	)
Net change due to revisions in quantity estimates		189,583			(63,547	)		—			479,618			5,959
Net change due to acquisition		—			4,158			—			2,840			—
Acquisition of remaining interest in equity affiliate		—			4,557			(4,557	)		—			—
Development costs incurred during the period		181,944			378,119			—			257,935			—
Difference in previously estimated development costs compared to actual costs incurred during the period		(3,282	)		(136,742	)		—			(87,408	)		—
Changes in estimated future development costs		(380,639	)		(398,534	)		—			(254,635	)		(214	)
Net change in future income taxes		248,639			545,702			—			(754,209	)		(4,673	)
Accretion of discount and other		108,508			614,478			—			(666,206	)		(4,454	)
Total discounted cash flow at end of period	$	894,351		$	1,218,434		$	—		$	1,384,983		$	4,557

Supplemental Quarterly Information (unaudited):

(Dollars in thousands)

	Three Months Ended
	March 31, 2009		June 30, 2009		September 30, 2009		December 31, 2009
Sales	$	1,164,341	$	1,003,973	$	1,032,531	$	1,158,937
Freight Revenue	$	30,916	$	27,087	$	36,130	$	54,774
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests’ Costs and Purchased Gas Costs)	$	680,095	$	649,704	$	714,627	$	751,444
Freight Expense	$	30,916	$	27,087	$	36,130	$	54,774
Net Income	$	204,971	$	118,839	$	93,286	$	150,046
Net Income Attributable to CONSOL Energy Inc Shareholders	$	195,819	$	113,339	$	87,370	$	143,189
Total Earnings per Share
Basic	$	1.08	$	0.63	$	0.48	$	0.80
Diluted	$	1.08	$	0.62	$	0.48	$	0.77
Weighted Average Shares Outstanding
Basic		180,576,479		180,644,498		180,725,194		180,823,733
Diluted		182,150,090		183,073,413		183,191,667		183,651,382
	Three Months Ended
	March 31, 2008		June 30, 2008		September 30, 2008		December 31, 2008
Sales	$	906,368	$	1,135,572	$	1,076,960	$	1,150,435
Freight Revenue	$	44,744	$	63,927	$	60,458	$	47,839
Cost of Goods Sold and Other Operating Charges (including Gas Royalty Interests’ Costs and Purchased Gas Costs)	$	656,223	$	764,137	$	762,767	$	742,213
Freight Expense	$	44,744	$	63,927	$	60,458	$	47,839
Net Income	$	84,231	$	112,790	$	102,416	$	186,224
Net Income Attributable to CONSOL Energy Inc Shareholders	$	75,082	$	101,012	$	90,054	$	176,322
Total Earnings per Share
Basic	$	0.41	$	0.55	$	0.49	$	0.98
Diluted	$	0.41	$	0.54	$	0.49	$	0.97
Weighted Average Shares Outstanding
Basic		182,572,985		182,977,726		183,202,086		180,799,712
Diluted		185,192,551		185,637,248		185,591,759		182,327,963

117