UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2010

Date of report (Date of earliest event reported):
May 6, 2011

RANGE RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware		001-12209		34-1312571
(State or other jurisdiction of incorporation)		(Commission File Number)		(IRS Employer Identification No.)

100 Throckmorton, Suite 1200 Ft. Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (817) 870-2601

(Former name or former address, if changed since last report): Not applicable

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligations of the registrant under any of the following provisions (see General Instruction A.2. below):

o		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

ITEM 8.01. OTHER EVENTS

     On April 29, 2011, we completed our previously announced sale of substantially all of our oil and gas leases, wells and related assets in the Barnett Shale play located in North Central Texas (Dallas, Denton, Ellis, Hill, Hood, Johnson, Parker, Tarrant and Wise Counties) for cash proceeds of $900.0 million including the assumption of certain derivative contracts and before normal closing adjustments. We reported our operations with respect to these properties as discontinued operations in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011.

     This Current Report on Form 8-K was prepared to provide revised financial information that presents these properties as discontinued operations for all periods presented in our Annual Report on Form 10-K for the year ended December 31, 2010, filed on March 1, 2011 (“2010 Form 10-K”). It should be noted that our net income (loss) was not impacted by the reclassification of our operations with respect to these properties to discontinued operations.

     Please note, we have not otherwise updated our financial information or business discussion for activities or events occurring after the date this information was presented in our 2010 Form 10-K. You should read our Quarterly Report on Form 10-Q for the period ended March 31, 2011 and our Current Reports on Form 8-K filed or furnished after the date of our 2010 Form 10-K and any amendments thereto, for updated information.

     This filing includes updated information for the following items included in our 2010 Form 10-K:

ITEM 6. SELECTED FINANCIAL DATA

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONIDTION AND RESULTS OF OPERATIONS

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Unaffected items of our 2010 Form 10-K have not been repeated in this Current Report on Form 8-K.

     Cross-references that are included in the above items and that refer to information included on page numbers that are preceded by an “F” refer to the corresponding page included in this filing. Other cross-references are to pages in our 2010 Form 10-K.

ITEM 6. SELECTED FINANCIAL DATA

     The following table shows selected financial information for the five years ended December 31, 2010. Significant producing property acquisitions and dispositions may affect the comparability of year-to-year financial and operating data. In the first half of 2010, we sold our Ohio properties for proceeds of $323.0 million. The financial and statistical data contained in the following discussion reflect our Barnett Shale operations, which were sold in April 2011 and our Gulf of Mexico operations, which were sold in 2007, as discontinued operations. This information should be read in conjunction with Item 7 of this report “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and related notes included elsewhere in this report.

		Year Ended December 31,
		2010				2009				2008				2007				2006
						(in thousands, except per share data)
Balance Sheet Data:
Current assets (a)		$	1,100,442			$	175,280			$	404,311			$	261,814			$	388,925
Current liabilities (b)			430,562				314,104				353,514				305,433				251,685
Natural gas and oil properties, net			4,084,013				3,551,635				3,466,028				2,665,324				2,076,637
Total assets			5,498,586				5,395,881				5,551,879				4,005,293				3,183,382
Bank debt			274,000				324,000				693,000				303,500				452,000
Subordinated notes			1,686,536				1,383,833				1,097,562				847,158				596,782
Stockholders’ equity (c)			2,223,761				2,378,589				2,451,342				1,717,736				1,258,089
Weighted average diluted shares outstanding			158,428				158,778				155,943				149,911				138,711
Cash dividends declared per common share			0.16				0.16				0.16				0.13				0.09
Statement of Cash Flow Data:
Net cash provided from operating activities		$	513,322			$	591,675			$	824,767			$	642,291			$	479,875
Net cash used in investing activities			(798,858	)			(473,807	)			(1,731,777	)			(1,020,572	)			(911,659	)
Net cash provided from (used in) financing activities			287,617				(117,854	)			903,745				379,917				429,416

		Year Ended December 31,
		2010				2009				2008				2007				2006
						(in thousands, except per share data)
Revenues and other income:
Natural gas, NGL and oil sales		$	760,453			$	714,564			$	989,307			$	743,166			$	572,268
Transportation and gathering			1,033				486				4,577				2,290				2,422
Derivative fair value income (loss)			51,634				66,446				71,861				(9,493	)			142,395
Gain on the sale of assets			76,642				10,413				20,166				20				21
Other			(963	)			(9,928	)			1,509				5,028				835
Total revenues and other income			888,799				781,981				1,087,420				741,011				717,941
Costs and expenses:
Direct operating			96,274				98,251				112,983				95,713				77,129
Production and ad valorem taxes			26,107				25,536				49,371				39,237				35,697
Exploration			60,506				44,276				56,956				43,437				39,662
Abandonment and impairment of unproved properties			49,738				36,935				15,292				7,282				1,427
General and administrative			140,571				115,319				92,308				69,670				49,886
Termination costs			8,452				2,479				—				—				—
Deferred compensation plan			(10,216	)			31,073				(24,689	)			35,438				(233	)
Interest expense			90,665				75,261				63,963				57,099				41,022
Loss on early extinguishment of debt			5,351				—				—				—				—
Depletion, depreciation and amortization			275,238				267,148				210,963				174,574				140,182
Impairment of proved properties			6,505				930				—				—				—
Total costs and expenses			749,191				697,208				577,147				522,450				384,772
Income from continuing operations before income taxes			139,608				84,773				510,273				218,561				333,169
Income tax (benefit) expense
Current			(836	)			(636	)			4,268				320				1,912
Deferred			51,746				46,429				176,912				84,688				125,904
			50,910				45,793				181,180				85,008				127,816
Income from continuing operations			88,698				38,980				329,093				133,553				205,353
Discontinued operations, net of taxes			(327,954	)			(92,850	)			21,947				83,715				(44,723	)
Net (loss) income		$	(239,256	)		$	(53,870	)		$	351,040			$	217,268			$	160,630
(Loss) income per common share:
Basic— income from continuing operations		$	0.56			$	0.25			$	2.18			$	0.93			$	1.53
—discontinued operations			(2.09	)			(0.60	)			0.14				0.58				(0.33	)
—net (loss) income		$	(1.53	)		$	(0.35	)		$	2.32			$	1.51			$	1.20
Diluted— income from continuing operations		$	0.55			$	0.24			$	2.11			$	0.89			$	1.48
—discontinued operations			(2.07	)			(0.58	)			0.14				0.56				(0.32	)
—net (loss) income		$	(1.52	)		$	(0.34	)		$	2.25			$	1.45			$	1.16

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions for the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information under Item 1.Business, Item 1A. Risk Factors, Item 6.Selected Financial Data and Item 8. Financial Statements Data in this report. Unless otherwise indicated, the information included herein relates to our continuing operations.

Overview of Our Business

     We are an independent natural gas and oil company engaged in the exploration, development and acquisition of primarily natural gas and oil properties, mostly in the Appalachian and Southwestern regions of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.

     Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to increase reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to economically find, develop, acquire and produce natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas, natural gas liquids and oil activities. Our corporate headquarters is located in Fort Worth, Texas.

Industry Environment

     We operate entirely within the United States. As traditional basins in the U.S. have matured, exploration and production has shifted to unconventional “resource” plays, typically shale reservoirs that historically were not thought to be productive for natural gas and oil. These plays cover large areas, provide multi-year inventories of drilling opportunities and, with modern oil and gas technology, have sustainable lower risk growth profiles. The economics of these plays have been enhanced by continued advancements in drilling and completion technologies. These advancements make these plays more resilient to lower commodity prices while increasing the domestic supply of natural gas and, with increased supply, an expected reduction in the volatility of natural gas prices. Examples of such technological advancements include advanced 3-D seismic processing, hydraulic reservoir fracture stimulation using almost one hundred percent sand and water, advances in well logging and analysis, horizontal drilling and completion technologies and automated remote well monitoring and control devices.

     Natural gas and oil are commodities. The price that we receive for the natural gas we produce is largely a function of market supply and demand in the United States. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of natural gas can result in price volatility. Factors impacting the future supply balance are the growth in domestic gas production and the increase in the United States’ LNG import capacity. Gas supplies in the United States have increased as a result of recent expansion in domestic unconventional gas production. Existing LNG import capacity may result in lower natural gas prices. Crude oil prices are generally determined by global supply and demand.

     The reduced liquidity provided by the worldwide financial markets and other factors that resulted in an economic slowdown in the United States and other industrialized countries in 2008 also resulted in reductions in worldwide energy demand. At the same time, North American gas supply increased as a result of the expansion in domestic unconventional natural gas production. The combination of lower demand due to the economic slowdown and higher North American gas supply resulted in declines in natural gas prices from their highs in mid-2008. Prices in 2010 and 2009 were more stable than in 2008. However, natural gas prices continue to be under pressure as a result of lower domestic demand and concerns over excess supply of natural gas due to high productivity of several emerging plays in the United States.

     Natural gas and oil gas prices affect:

•

the amount of cash flow available to us for capital expenditures;

•

our ability to borrow and raise additional capital;

•

the quantity of natural gas and oil that we can economically produce;

•

revenues and profitability; and

•

the accounting for our natural gas and oil activities.

     Any continued or extended decline in natural gas and oil prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital.

Capital Budget for 2011

     Our capital budget for 2011 is currently set at $1.38 billion, excluding acquisitions. The 2011 capital budget is more than the 2010 capital spending levels with higher expected operating cash flows resulting from higher production. For 2011, we expect our operating cash flow and proceeds from asset sales to fund our capital budget. As has been our historical practice, we will periodically review our capital expenditures throughout the year and adjust the budget based on commodity prices, drilling success and other factors.

Source of Our Revenues

     We derive our revenues from the sale of natural gas, natural gas liquids (“NGLs”) and oil that is produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, quality, Btu content and transportation costs to market. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our natural gas and oil production. The use of derivative instruments has in the past and may in the future, prevent us from realizing the full benefit of upward price movements but also protects us from declining price movements. Our average realized price calculations (including all derivative settlements) include the effects of the settlement of all derivative contracts regardless of the accounting treatment. Discontinued operations include our Barnett Shale properties which were sold in April 2011. Unless indicated otherwise, the information included herein relates to our continuing operations.

Principal Components of Our Cost Structure

•

Direct Operating Expenses. These are day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workovers expenses related to our natural gas and oil properties. These costs are expected to remain a function of supply and demand. Direct operating expenses also include stock-based compensation expense (non-cash) associated with grants of stock appreciation rights (SARs) and the amortization of restricted stock grants as part of employee compensation.

•

Production and Ad Valorem Taxes. Production taxes are paid on produced natural gas and oil based on a percentage of market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. Ad valorem taxes are generally based on reserve values at the end of each year.

•

Exploration Expenses. These are geological and geophysical costs, including payroll and benefits for the geological and geophysical staff, seismic costs, delay rentals and the costs of unsuccessful exploratory dry holes. Exploration expense also includes stock-based compensation expense (non-cash) associated with grants of SARs and the amortization of restricted stock grants as part of employee compensation.

•

Abandonment and impairment of unproved properties. This category includes unproved property impairment and costs associated with lease expirations.

•

General and Administrative Expenses. These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance. Included in this category are overhead expense reimbursements we receive from working interest owners of properties, for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. General and administrative expense also includes stock-based compensation expense (non-cash) associated with grants of SARs and the amortization of restricted stock grants as part of employee compensation.

•

Deferred Compensation Plan Expense. These costs relate to the increase or decrease in the value of the liability associated with our deferred compensation plan. Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion.

•

Interest. We typically finance a portion of our working capital requirements and acquisitions with borrowings under our bank credit facility and with longer-term debt securities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We will likely continue to incur interest expense as we continue to grow.

•

Depreciation, Depletion and Amortization Expense. This includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This expense also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as wells, service assets, pipelines, and other facilities.

•

Income Taxes. We are subject to state and federal income taxes but are currently not in a cash taxpaying position for federal income taxes, primarily due to the current deductibility of intangible drilling costs (“IDC”). We do pay some state income taxes where our IDC deductions do not exceed our taxable income or where state income taxes are determined on a basis other than federal taxable income. Currently, substantially all of our federal taxes are deferred and we anticipate using all of our net operating loss carryforwards. For additional information, see “Risk Factors-Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation,” in Item 1A of this report.

Management’s Discussion and Analysis of Income and Operations

Market Conditions

     Prices for various quantities of natural gas, natural gas liquids (“NGLs”) and oil that we produce significantly impact our revenues and cash flows. Commodity prices have been volatile in recent years. The following table lists average New York Mercantile Exchange (“NYMEX”) prices for natural gas and oil for the year ended December 31, 2010, 2009 and 2008.

		Year Ended
		December 31,
		2010				2009				2008
Average NYMEX prices (a)
Natural gas (per mcf)		$	4.39			$	4.02			$	8.94
Oil (per bbl)		$	79.59			$	60.48			$	100.49

Overview of 2010 Results

     During 2010, we achieved the following financial and operating results:

•

achieved 21% production growth;

•

achieved 42% proved reserve growth (including our Barnett Shale properties);

•

drilled 266 net wells with a 98% success rate (including our Barnett Shale properties);

•

continued expansion of our activities in the Marcellus Shale by growing production, proving up acreage and acquiring additional unproved acreage;

•

reduced direct operating expenses per mcfe 19%;

•

reduced DD&A rate 15%;

•

maintained a strong balance sheet by retaining a debt to capitalization ratio of 47% and issuing $500.0 million of new senior subordinated notes;

•

used a portion of the proceeds from the issuance of $500.0 million of our 6.75% senior subordinated notes due 2020 to redeem all $200.0 million aggregate principal amount of our 7.375% senior subordinated notes due 2013;

•

entered into additional derivative contracts for 2011 and 2012;

•

received proceeds of $327.8 million from asset sales;

•

realized $513.3 million of cash flow from operating activities; and

•

ended the year with stockholders’ equity of $2.2 billion.

     Operationally, our 2010 performance reflects another year of successfully executing our strategy of growth through drilling. Our success enabled us to increase proved reserves by 1.3 Tcf, which is more than seven times 2010 production (including production and reserves from our Barnett Shale properties). During 2010, we also purchased 125.0 Bcfe of proved reserves through acquisitions. As evidenced by history, commodity prices are inherently volatile. To maintain our competitive advantage, we have focused our efforts on improving operating efficiency. As reservoirs are depleted and production rates decline, per unit production costs will generally increase. Our production is focused in core areas where we can achieve economies of scale to help manage our operating costs. Our efforts resulted in lower direct operating expense on an absolute dollar basis and on a per mcfe basis for 2010 when compared to 2009 and 2008. We also have continued to expand and develop our natural gas shale plays with most of our focus on the Marcellus Shale. We exited the year producing approximately 212.0 Mmcfe per day in the Marcellus Shale. We drilled 117 net wells, increasing our Marcellus reserves to over 1.9 Tcfe. We will continue to evaluate our Marcellus Shale leases and formulate our development plans for this area.

     Total revenues increased 14% in 2010 over the same period of 2009. This increase was due to higher production and a gain on the sale of assets somewhat offset by lower realized natural gas and oil prices. Our 2010 production growth was due to the continued success of our drilling program. Average realized prices (including all derivative settlements) were 27% lower in 2010. As discussed in Item 1A of this report, significant changes in natural gas and oil prices can have a material impact on our results of operations and our balance sheet, including the fair value of our derivatives.

2011 Outlook

     For 2011, the Board has approved a $1.38 billion capital budget for natural gas and oil related activities, excluding proved property acquisitions. We expect to fund our 2011 capital budget expenditures with cash flows from operations and proceeds from asset sales. The price risk on a portion of our forecasted natural gas and oil production for 2011 is mitigated using commodity derivative contracts and we intend to continue to enter into these transactions. The prices we receive for our natural gas and oil production are largely based on current market prices, which are beyond our control. In October 2010, we announced our plan to offer for sale our Barnett Shale properties in North Texas and the data room opened in December 2010. These properties included approximately 360 producing wells and 700 proven and unproven drilling locations. On February 28, 2011, we announced that we had entered into a definitive agreement to sell these assets along with certain derivative contracts for a price of $900.0 million, subject to typical post-closing adjustments. On April 29, 2011, we sold substantially all of the Barnett Shale properties. The approximate net book value of these assets at December 31, 2010 was $835.9 million, which excludes the derivative contracts being sold. For additional information related to this sale, see Note 3 and Note 4 to the consolidated financial statements.

Natural Gas, NGL and Oil Sales, Production and Realized Price Calculations

     Our revenues vary from year to year as a result of changes in realized commodity prices and production volumes. Hedges included in natural gas, NGL and oil sales reflect settlements on those derivatives that qualify for hedge accounting. Cash settlements of derivative contracts that are not accounted for as hedges are included in derivative fair value income in the accompanying statements of operations. In 2010, natural gas, NGL and oil sales increased 6% from 2009 with a 21% increase in production partially offset by a 12% decrease in realized prices. In 2009, natural gas, NGL and oil sales decreased 28% from 2008 due to a 33% decrease in realized prices partially offset by a 8% increase in production. The following table illustrates the primary components of natural gas, NGL and oil sales for each of the last three years (in thousands):

		2010				2009				2008
Natural gas, NGL and oil sales
Gas wellhead		$	418,727			$	324,943			$	704,770
Gas hedges realized			64,749				190,934				8,561
Total gas revenue		$	483,476			$	515,877			$	713,331
Total NGL revenue		$	143,132			$	48,094			$	52,351
Oil wellhead		$	133,822			$	138,597			$	294,608
Oil hedges realized			23				11,996				(70,983	)
Total oil revenue		$	133,845			$	150,593			$	223,625
Combined wellhead		$	695,681			$	511,634			$	1,051,729
Combined hedges			64,772				202,930				(62,422	)
Total natural gas, NGL and oil sales		$	760,453			$	714,564			$	989,307

     Our production continues to grow through drilling success as we place new wells into production and through additions from acquisitions partially offset by the natural decline of our natural gas and oil wells and asset sales. For 2010, our production volumes increased 43% in the Appalachian region and declined 8% in our Southwestern region. Included in the 2010 increase in our Appalachian region is the effect of the sale of our Ohio tight gas sand properties. For 2009, our production volumes increased 28% in the Appalachian region and declined 10% in the Southwestern region. Crude oil production declined from 2008 primarily due to the sale of certain oil properties in West Texas. Our production for each of the last three years is set forth in the following table:

		2010				2009				2008
Production (a)
Natural gas (mcf)			106,147,511				90,570,364				82,158,559
NGLs (bbls)			3,600,469				1,585,332				1,032,071
Crude oil (bbls)			1,934,417				2,522,784				3,045,710
Total (mcfe) (b)			139,356,832				115,219,062				106,625,245
Average daily production (a)
Natural gas (mcf)			290,815				248,138				224,477
NGLs (bbls)			9,864				4,343				2,820
Crude oil (bbls)			5,300				6,912				8,322
Total (mcfe) (b)			381,800				315,668				291,326

     Our average realized price (including all derivative settlements) received during 2010 was $5.71 per mcfe compared to $7.80 per mcfe in 2009 and $9.13 per mcfe in 2008. Our average realized price (including all derivative settlements) calculation includes all cash settlements for derivatives, whether or not they qualify for hedge accounting, except for the year ended December 31, 2010, we have excluded from average realized price calculations a $15.7 million gain related to an early settlement of oil collars. The average prices below reflect average realized prices included in continuing operations, which includes all derivatives not specifically designated to discontinued operations. Average price calculations for each of the last three years are shown below:

		2010				2009				2008
Average Prices
Average sales prices (wellhead):
Natural gas (per mcf)		$	3.94			$	3.60			$	8.58
NGLs (per bbl)			39.75				30.34				50.72
Crude oil (per bbl)			69.18				54.94				96.73
Total (per mcfe) (a)			4.99				4.44				9.86
Average realized prices (including derivatives that qualify for hedge accounting):
Natural gas (per mcf)			4.55				5.70				8.68
NGLs (per bbl)			39.75				30.34				50.72
Crude oil (per bbl)			69.19				59.69				73.42
Total (per mcfe) (a)			5.46				6.20				9.28
Average realized prices (including all derivative settlements):
Natural gas (per mcf)			4.89				7.65				8.69
NGLs (per bbl)			39.75				30.34				50.72
Crude oil (per bbl)			69.19				62.57				68.17
Total (per mcfe) (a)			5.71				7.80				9.13

     Derivative fair value income was $51.6 million in 2010 compared to $66.4 million in 2009 and to $71.9 million in 2008. Some of our derivatives do not qualify for hedge accounting and are accounted for using the mark-to-market accounting method whereby all realized and unrealized gains and losses related to these contracts are included in derivative fair value income in the accompanying consolidated statements of operations. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying consolidated balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Any gains on our derivatives will be offset by lower wellhead revenues in the future or any losses will be offset by higher future wellhead revenues based on the value at the settlement date. At December 31, 2010, all of our derivative contracts are recorded at their fair value, which was a net asset of $117.7 million (including $8.2 million related to discontinued operations), an increase of $106.8 million from the $10.9 million net asset recorded as of December 31, 2009. We have also entered into basis swap agreements to limit volatility caused by changing differentials between index and regional prices received. These basis swaps do not qualify for hedge accounting and are marked to market. Hedge ineffectiveness, also included in derivative fair value income, is associated with contracts that qualify for hedge accounting. The ineffective portion is calculated as the difference between the change in the fair value of the derivative and the estimated change in future cash flows from the item being hedged.

     The following table presents information about the components of derivative fair value income for each of the years in the three-year period ended December 31, 2010 (in thousands):

		2010				2009				2008
Change in fair value of derivatives that do not qualify for hedge accounting (a)		$	(2,086	)		$	(115,909	)		$	85,594
Realized gain (loss) on settlements — natural gas (b) (c)			35,988				171,998				(1,383	)
Realized gain (loss) on settlements — oil (b) (c)			—				7,304				(15,431	)
Realized gain on early settlement of oil derivatives (d)			15,697				—				—
Hedge ineffectiveness — realized (c)			(352	)			4,749				1,386
— unrealized (a)			2,387				(1,696	)			1,695
Derivative fair value income		$	51,634			$	66,446			$	71,861

     Gain on the sale of assets was $76.6 million in 2010 compared to $10.4 million in 2009 and $20.2 million in 2008. During 2010, we sold our tight gas sand properties in Ohio for proceeds of approximately $323.0 million and recorded a gain of $77.6 million. The 2009 period includes a $10.4 million gain on the sale of Marcellus acreage. The 2008 period includes the sale of East Texas properties for proceeds of $64.0 million and a gain of $20.2 million was recorded.

     Other revenue in 2010 was a loss of $963,000 compared to a loss of $9.9 million in 2009 and income of $1.5 million in 2008. The 2010 period includes a loss from equity method investments of $1.5 million partially offset by proceeds of $486,000 from a lawsuit settlement. The 2009 period includes a loss from equity method investments of $13.7 million partially offset by proceeds of $3.8 million from a lawsuit settlement. The 2008 period includes a loss from equity method investments of $218,000.

     We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for 2010, 2009 and 2008.

		Year Ended December 31,																Year Ended December 31,
		2010				2009				Change				% Change				2009				2008				Change				% Change
Direct operating expense		$	0.69			$	0.85			$	(0.16	)			(19	%)		$	0.85			$	1.06			$	(0.21	)			(20	%)
Production and ad valorem tax expense			0.19				0.22				(0.03	)			(14	%)			0.22				0.46				(0.24	)			(52	%)
General and administrative expense			1.01				1.00				0.01				1	%			1.00				0.87				0.13				15	%
Interest expense			0.65				0.65				—				—				0.65				0.60				0.05				8	%
Depletion, depreciation and amortization expense			1.98				2.32				(0.34	)			(15	%)			2.32				1.98				0.34				17	%

     Direct operating expense was $96.3 million in 2010 compared to $98.3 million in 2009 and $113.0 million in 2008. We experience increases in operating expenses as we add new wells and maintain production from existing properties. In 2010 and 2009, this effect was more than offset by asset sales, lower overall industry costs and lower workover expenses. On an absolute dollar basis, our spending for direct operating expenses for 2010 was lower when compared to 2009 despite higher production levels, reflecting our asset sales and lower overall industry costs. The sale of our Ohio properties in 2010 and the sale of our New York and West Texas properties in 2009 make comparisons of 2010 to 2009 difficult. On a pro forma basis, excluding our Ohio, New York and West Texas sold properties, 2009 direct operating expenses from continuing operations would have been $75.7 million and 2010 direct operating expense from continuing operations would have been $93.6 million. On an absolute dollar basis, our spending for direct operating expenses for 2009 was lower when compared to 2008 despite higher production levels reflecting cost containment measures and lower overall industry costs. We incurred $3.4 million of workover costs in 2010 compared to $5.0 million in 2009 and $5.9 million in 2008.

     On a per mcfe basis, direct operating expense for 2010 decreased $0.16 or 19% from the same period of 2009, with the decrease consisting of primarily lower workover costs ($0.02 per mcfe), lower overall well service costs and asset sales. On a pro forma basis, excluding the sale of our Ohio properties in 2010 and the sale of our New York and West Texas properties in 2009, 2009 direct operating expense from continuing operations would have been $0.74 per mcfe and 2010 direct operating expense from continuing operations would have been $0.68 per mcfe. On a per mcfe basis, direct operating expense for 2009 decreased $0.21 or 20% from the same period of 2008 with the decrease consisting primarily of lower workover costs ($0.02

per mcfe), lower utility costs ($0.03 per mcfe), lower well service costs, asset sales and our focus on cost containment. We expect to continue to experience lower costs per mcfe as we increase production from our Marcellus Shale wells due to their lower operations cost relative to our other operating areas. Stock-based compensation expense represents the amortization of restricted stock grants and SARs as part of employee compensation. The following table summarizes direct operating expenses per mcfe for 2010, 2009 and 2008:

		Year Ended December 31,																Year Ended December 31,
		2010				2009				Change				% Change				2009				2008				Change				% Change
Lease operating expense		$	0.66			$	0.79			$	(0.13	)			(16	%)		$	0.79			$	0.97			$	(0.18	)			(19	%)
Workovers			0.02				0.04				(0.02	)			(50	%)			0.04				0.06				(0.02	)			(33	%)
Stock-based compensation (non-cash)			0.01				0.02				(0.01	)			(50	%)			0.02				0.03				(0.01	)			(33	%)
Total direct operating expenses		$	0.69			$	0.85			$	(0.16	)			(19	%)		$	0.85			$	1.06			$	(0.21	)			(20	%)

     Production and ad valorem taxes are paid based on market prices, not hedged prices. These costs were $26.1 million in 2010 compared to $25.5 million in 2009 and $49.4 million in 2008. On a per mcfe basis, production and ad valorem taxes decreased to $0.19 in 2010 compared to $0.22 in 2009 due to an increase in production volumes not subject to production or ad valorem taxes. On a per mcfe basis, production and ad valorem taxes decreased to $0.22 in 2009 from $0.46 in 2008 due to a 55% decrease in pre-hedge prices.

     General and administrative expense was $140.6 million for 2010 compared to $115.3 million for 2009 and $92.3 million in 2008. The 2010 increase of $25.3 million when compared to 2009 is due to higher salaries and benefits ($4.6 million), an increase in legal fees and legal settlements ($4.2 million), an increase in community relations costs ($6.5 million), higher bad debt expense ($2.3 million), higher office expenses, including information technology ($1.8 million), and higher industry trade association dues and inventory adjustments. While our number of employees declined 9% during 2010 due to our asset sales, we continue to incur higher wages which we consider necessary to remain competitive in the industry. The 2009 increase of $23.0 million when compared to 2008 is due primarily to higher salaries and benefits ($11.7 million) due to an increase in the number of employees (4%) and salary increases, higher stock based compensation ($9.7 million), higher legal fees and office expenses, including rent and information technology and higher bad debt expense ($1.4 million). Our personnel costs continue to increase as we invest in our technical teams and other staffing to support our expansion into the Marcellus Shale in Appalachia. Stock-based compensation expense represents the amortization of restricted stock grants and SARs granted to our employees and directors as part of compensation. The following table summarizes general and administrative expenses per mcfe for 2010, 2009 and 2008:

		Year Ended December 31,																Year Ended December 31,
		2010				2009				Change				% Change				2009				2008				Change				% Change
General and administrative		$	0.76			$	0.71			$	0.05				7	%		$	0.71			$	0.65			$	0.06				9	%
Stock-based compensation (non-cash)			0.25				0.29				(0.04	)			(14	%)			0.29				0.22				0.07				32	%
Total general and administrative expenses		$	1.01			$	1.00			$	0.01				1	%		$	1.00			$	0.87			$	0.13				15	%

     Interest expense was $90.7 million for 2010 compared to $75.3 million for 2009 and $64.0 million in 2008. Interest expense for 2010 increased $15.4 million from the same period of 2009 due to the refinancing of certain debt from floating rates to higher fixed rates. In August 2010, we issued $500.0 million of 6.75% senior subordinated notes due 2020, which added $13.0 million of interest costs in 2010. The proceeds from this issuance was used to retire bank debt which carried a lower interest rate and to redeem all $200.0 million of our 7.375% senior subordinated notes due 2013. Interest expense for 2009 increased $11.3 million from the same period of 2008 due to the refinancing of certain debt from floating rates to higher fixed rates and higher average debt balances. In May 2009, we issued $300.0 million of 8% senior subordinated notes due 2019, which added $15.1 million of interest costs in 2009. In May 2008, we issued $250.0 million of 7.25% senior subordinated notes due 2018, which added $11.8 million of interest costs in 2008. The 2010, 2009 and 2008 note issuances were undertaken to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for 2010 was $351.1 million compared to $584.5 million for 2009 and $494.2 million for 2008 and the weighted average interest rate was 2.2% in 2010 compared to 2.4% in 2009 and 4.4% in 2008.

     Depletion, depreciation and amortization (“DD&A”) was $275.2 million in 2010 compared to $267.1 million in 2009 and $211.0 million in 2008. The decrease in 2010 compared to 2009 is due to a 9% decrease in depletion rates and lower depreciation expense partially offset by a 21% increase in production. 2009 included accelerated depreciation expense of $10.3 million on an interim processing plant in Appalachia that was dismantled in the first quarter of 2010 and replaced with

permanent facilities. The increase in DD&A for 2009 compared to 2008 is due to a 8% increase in production, a 11% increase in depletion rates and accelerated depreciation expense of $10.3 million on an interim processing plant in Appalachia. On a per mcfe basis, DD&A decreased to $1.98 in 2010 compared to $2.32 in 2009 and $1.98 in 2008. Depletion expense, the largest component of DD&A, was $1.82 per mcfe in 2010 compared to $1.99 per mcfe in 2009 and $1.80 per mcfe in 2008. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. In areas where we are actively drilling, such as the Marcellus area, fourth quarter 2010 depletion rates were lower than 2009. Depletion rates in new plays tend to be higher in the beginning as increased initial outlays are amortized over proved reserves based on early stages of evaluations. The decrease in the DD&A per mcfe in 2010 when compared to 2009 is related to lower depreciation expense and the mix of our production. The increase in DD&A per mcfe in 2009 when compared to 2008 was related to the accelerated depreciation expense on an interim processing plant ($0.09) and the mix of our production. The following table summarizes DD&A expense per mcfe for 2010, 2009 and 2008:

		Year Ended December 31,																Year Ended December 31,
		2010				2009				Change				% Change				2009				2008				Change				% Change
Depletion and amortization		$	1.82			$	1.99			$	(0.17	)			(9	%)		$	1.99			$	1.80			$	0.19				11	%
Depreciation			0.12				0.28				(0.16	)			(57	%)			0.28				0.13				0.15				115	%
Accretion and other			0.04				0.05				(0.01	)			(20	%)			0.05				0.05				—				—	%
Total DD&A expense		$	1.98			$	2.32			$	(0.34	)			(15	%)		$	2.32			$	1.98			$	0.34				17	%

Other Operating Expenses

     Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense, abandonment and impairment of unproved properties and deferred compensation plan expenses. In 2010, stock-based compensation was a component of direct operating expense ($2.0 million), exploration expense ($4.2 million), general and administrative expense ($34.2 million) and termination costs ($2.8 million) for a total of $44.4 million. In 2009, stock-based compensation was a component of direct operating expense ($2.5 million), exploration expense ($4.7 million) and general and administrative expense ($33.3 million) and termination costs of $332,000 for a total of $41.6 million. In 2008, stock-based compensation was a component of direct operating expense ($2.7 million), exploration expense ($4.1 million) and general and administrative expense ($23.8 million) for a total of $31.1 million. Stock-based compensation includes the amortization of restricted stock grants and SARs grants.

     Exploration expense was $60.5 million in 2010 compared to $44.3 million in 2009 and $57.0 million in 2008. The following table details our exploration-related expenses for 2010, 2009 and 2008. Exploration expense was significantly higher in 2010 when compared to 2009 due to higher delay rental costs, or the costs we incur to defer the commencement of drilling, primarily in our Marcellus Shale operations. Exploration expense was significantly lower in 2009 when compared to 2008 due to our focus on development of our large shale and coal bed methane projects and the closure of our Gulf Coast office. The following table details our exploration related expenses for 2010, 2009 and 2008 (in thousands):

		Year Ended December 31,																Year Ended December 31,
		2010				2009				Change				% Change				2009				2008				Change				% Change
Seismic		$	22,393			$	19,834			$	2,559				13	%		$	19,834			$	24,985			$	(5,151	)			(21	%)
Delay rentals and other			19,075				6,836				12,239				179	%			6,836				5,103				1,733				(34	%)
Personnel expense			11,129				10,743				386				4	%			10,743				11,804				(1,061	)			(9	%)
Stock-based compensation expense			4,209				4,703				(494	)			(11	%)			4,703				4,130				573				14	%
Dry hole expense			3,700				2,160				1,540				71	%			2,160				10,934				(8,774	)			(80	%)
Total exploration expense		$	60,506			$	44,276			$	16,230				37	%		$	44,276			$	56,956			$	(12,680	)			(22	%)

     Abandonment and impairment of unproved properties was $49.7 million in 2010 compared to $36.9 million in 2009 and $15.3 million in 2008. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments will likely be recorded.

     Termination costs in 2010 includes severance costs of $5.1 million related to the sale of our Ohio properties and $2.8 million of non-cash stock-based compensation expense related to the accelerated vesting of SARs and restricted stock as part of the severance agreement for our Ohio personnel. Termination costs in 2009 represent severance costs related to the closing of our Houston office ($1.6 million), $332,000 of non-cash stock-based compensation expense related to the accelerated vesting of SARs and restricted stock as part of the severance agreement for our Houston personnel and $635,000 of severance costs related to the sale of our New York properties.

     Deferred compensation plan expense was a gain of $10.2 million in 2010 compared to a loss of $31.1 million in 2009 and a gain of $24.7 million in 2008. Our stock price decreased to $44.98 at December 31, 2010 compared to $49.85 at December 31, 2009. Our stock price increased to $49.85 at December 31, 2009 compared to $34.39 at December 31, 2008. This non-cash item relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense.

     Loss on early extinguishment of debt expense for 2010 was $5.4 million. In August 2010, we redeemed our 7.375% senior subordinated notes due 2013 at a redemption price equal to 101.229%. We recorded a loss on extinguishment of debt of $5.4 million which includes call premium costs of $2.5 million and expensing of related deferred financing costs on the repurchased debt.

     Impairment of proved properties increased to $6.5 million compared to $930,000 in 2009. The year ended 2010 includes a $6.5 million impairment related to our onshore Gulf Coast properties. In 2009, we recognized $930,000 impairment related to our Michigan properties. These assets were reviewed for impairment due to declining reserves and natural gas prices.

     Income tax expense was $50.9 million compared to $45.8 million in 2009 and $181.2 million in 2008. The 2010 increase in income taxes reflects a 65% increase in income from continuing operations before income taxes when compared to the same period of 2009. The effective tax rate in 2010 was 36.5% compared to an effective tax rate of 54.0% in 2009. For the year ended December 31, 2010, the current income tax benefit of $836,000 is related to state income taxes. The 2010 effective tax rate was different than the statutory rate of 35% due to an increase in our valuation allowances related to our deferred tax asset for future deferred compensation plan distributions of top executives to the extent their estimated future compensation (including these distributions) would exceed the $1.0 million deductible limit provided under section 162(M) of the Internal Revenue Code. The 2009 decrease reflects an 83% decrease in continuing income before income taxes compared to the same period of 2008. The year ended December 31, 2009 also includes an unfavorable $16.3 million charge to reflect updated state tax rates used to establish deferred taxes due to a change in our state apportionment factors to states with higher rates, particularly in Pennsylvania, with our increased focus on development of the Marcellus Shale, along with increased proved reserves and acreage in Pennsylvania. The 2009 effective tax rate was 54% compared to an effective tax rate in 2008 of 35.5%. For the year ended December 31, 2009, the current income tax benefit of $636,000 includes state income taxes of $364,000 and a federal income tax benefit of $1.0 million. The effective tax rate was different than the statutory rate of 35% due to an increase in our state apportionment factors in certain higher-rate states, offset by a benefit related to a partial release of valuation allowance on our capital loss carryforward. The 2008 current income taxes of $4.3 million include state income taxes of $3.3 million and $1.0 million of federal income taxes and the effective tax rate was different than the statutory rate of 35% due to state income taxes. We expect our effective tax rate to be approximately 38-39% for 2011.

     Discontinued operations include the operating results and impairment losses related to our Barnett properties. These properties were sold on April 29, 2011 for proceeds of $900.0 million including certain derivatives and before normal closing adjustments. Discontinued operations in 2010 was a loss of $328.0 million compared to a loss of $92.9 million in 2009 and income of $21.9 million in 2008. The twelve months ended 2010 includes an impairment charge of $463.2 million. While these properties did not meet held for sale criteria as of December 31, 2010, our analysis reflected undiscounted cash flows for these properties were less than their carrying value. Therefore, we compared the carrying value of these properties to their estimated fair value and recognized an impairment charge. For the year ended 2010, price realizations increased 26% somewhat offset by a 6% decline in production, when compared to the same period of the prior year. Price realization in 2009 declined 58% from the same period of 2008 somewhat offset by a 27% increase in production. See also Note 4 to the accompanying financial statements. Interest expense is allocated to discontinued operations based on the ratio of net assets of discontinued operations to our consolidated net assets plus long-term debt.

Management’s Discussion and Analysis of Financial Condition, Capital Resources and Liquidity

     Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit facility with uncommitted and committed availability, asset sales and access to the debt and equity capital markets. We continue to take steps to ensure adequate capital resources and liquidity to fund our capital expenditure program. During 2010, we sold our shallow tight gas sand Ohio properties for proceeds of approximately $323.0 million. We used a portion of these proceeds to purchase proved and unproved properties primarily in Virginia. The remainder of these proceeds was used to repay amounts under our bank credit facility. In 2010, we entered into additional commodity derivative contracts for 2011 and 2012 to protect

future cash flows. As part of our semi-annual bank review completed October 8, 2010, our borrowing base and facility amounts were reaffirmed at $1.5 billion and $1.25 billion. On February 18, 2011, we announced we have entered into an amended and restated revolving bank facility, which replaced our previous bank credit facility. The new facility, secured by substantially all of our assets, provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. At closing, the borrowing base amount was $2.0 billion and the facility amount was $1.5 billion.

     During 2010, our net cash provided from continuing operations of $433.9 million, proceeds from the sale of assets of $327.8 million and borrowings under our bank credit facility were used to fund $1.0 billion of capital expenditures (including acquisitions and equity investments). At December 31, 2010, we had $2.8 million in cash and total assets of $5.5 billion. Our debt to capitalization ratio was 47%. As of December 31, 2010 and 2009, our total debt and capitalization were as follows (in thousands):

		2010				2009
Bank debt		$	274,000			$	324,000
Senior subordinated notes			1,686,536				1,383,833
Total debt			1,960,536				1,707,833
Stockholders’ equity			2,223,761				2,378,589
Total capitalization		$	4,184,297			$	4,086,422
Debt to capitalization ratio			46.9	%			41.8	%

     Long-term debt at December 31, 2010 totaled $2.0 billion, including $274.0 million of bank credit facility debt and $1.7 billion of senior subordinated notes. Our available committed borrowing capacity at December 31, 2010 was $970.6 million. Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves that are typical in the oil and natural gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We currently believe that net cash generated from operating activities, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales combined with our natural gas and oil hedges currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. However, long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and natural gas business. A material drop in natural gas and oil prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, reduce debt, meet financial obligations and remain profitable. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of natural gas and oil, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings, asset sales or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to offset inherent declines in production and proven reserves.

     Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance, the state of the worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate and, in particular, with respect to borrowings, the level of our working capital or outstanding debt and credit ratings by rating agencies. For additional information, see “Risk Factors-Difficult Conditions in the global capital markets, the credit markets and the economy generally may materially adversely affect our business and results of operations” in Item 1A of this report.

Credit Arrangements

     As of December 31, 2010, we maintained a $1.25 billion revolving credit facility, which we refer to as our bank credit facility. The bank credit facility was secured by substantially all of our assets with a maturity of October 25, 2012. Availability under the bank credit facility was subject to a borrowing base set by the lenders semi-annually with an option to set more often in certain circumstances. The borrowing base was dependent on a number of factors but primarily the lenders’ assessment of future cash flows. Redeterminations of the borrowing base required approval of 2/3rds of the lenders; increases required unanimous approval.

     On February 18, 2011, we entered into an amended and restated revolving credit facility, which replaced our previous bank credit facility. The new bank credit facility, secured by substantially all of our assets, provides for an initial commitment equal to the lesser of the facility amount or the borrowing base. The new bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and for event-driven unscheduled redeterminations. At February 25,

2011, the bank credit facility had a $2.0 billion borrowing base and a $1.5 billion facility amount. Borrowings under the new credit facility can either be, at our election: (i) at the Alternate Base Rate (as defined in the credit agreement) plus a spread ranging from 0.5% to 1.5% or (ii) LIBOR borrowings at the Adjusted LIBO Rate (as defined in the credit agreement) plus a spread ranging from 1.5% to 2.5%. Remaining credit availability was $1.1 billion on February 25, 2011. Our new bank group is comprised of twenty-seven commercial banks, with no one bank holding more than 7.0% of the bank credit facility. The new credit facility matures on February 18, 2016. For additional information, see Note 8 to our consolidated financial statements.

     Our bank debt and our subordinated notes impose limitations on the payment of dividends and other restricted payments (as defined under the debt agreements for our bank debt and our subordinated notes). The debt agreements also contain customary covenants relating to debt incurrence, working capital, dividends and financial ratios. We were in compliance with all covenants at December 31, 2010.

Capital Requirements

     Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties, repayment of principal and interest on outstanding debt and payment of dividends. During 2010, $838.7 million of capital was expended on drilling projects. Also in 2010, $151.6 million was expended on acquisitions of unproved acreage, primarily in the Marcellus Shale and $134.5 million was expended to purchase proved and unproved properties in Virginia. Our 2010 capital program, excluding acquisitions, was funded by net cash flow from operations, proceeds from asset sales and borrowings under our credit facility. Our capital expenditure budget for 2011 is currently set at $1.38 billion, excluding acquisitions. Development and exploration activities are highly discretionary, and, for the near term, we expect such activities to be maintained at levels equal to internal cash flow and asset sales. To the extent, capital requirements exceed internal cash flow and proceeds from asset sales, debt or equity may be issued to fund these requirements. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and also between our operating regions, depending on commodity prices, cash flow and projected returns. Also, our obligations may change due to acquisitions, divestitures and continued growth. We may issue additional shares of stock, subordinated notes or other debt securities to fund capital expenditures, acquisitions, extend maturities or to repay debt.

     The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for natural gas and oil, actions of competitors, disruptions or interruptions of our production and unforeseen hazards such as weather conditions, acts of war or terrorists acts and the government or military response, and other operating and economic considerations.

Cash Flow

     Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations also are impacted by changes in working capital. We generally maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity needs are satisfied by borrowings under our bank credit facility. Because of this, and since our principal source of operating cash flows (or proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. We sell substantially all of our production at the wellhead under floating market contracts. However, we generally hedge a substantial, but varying portion of our anticipated future natural gas and oil production for the next 12 to 24 months. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowings under the credit facility. As of December 31, 2010, we have entered into hedging agreements covering 161.0 Bcfe for 2011 (which includes agreements related to our Barnett Shale properties) and 58.5 Bcfe for 2012.

     Net cash provided from continuing operations in 2010 was $433.9 million compared to $554.2 million in 2009 and $655.5 million in 2008. Cash provided from continuing operations is largely dependent upon commodity prices and production, net of the effects of settlement of our derivative contracts. The decrease in cash provided from operating activities from 2009 to 2010 reflects lower price realization (a decline of 27%) somewhat offset by a 21% increase in production. The decrease in cash provided from continuing operations from 2008 to 2009 reflects lower price realizations (a decline of 15%) somewhat offset by a 8% increase in production. As of December 31, 2010, we have hedged approximately 81% of our projected 2011 production and 24% of our projected 2012 production. Net cash provided from continuing operations is also affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statements of cash flows) for 2010 was a negative $14.9 compared to a negative $42.8 million for 2009 and positive $8.9 million in 2008.

     Net cash used in investing activities from continuing operations in 2010 was $714.7 million compared to $289.0 million in 2009 and $1.1 billion in 2008.

     During 2010, we:

	•		spent $732.9 million on natural gas and oil property additions;
	•		spent $296.5 million on acquisitions, including purchasing unproved and proved properties in Virginia for $134.5 million and Marcellus Shale leaseholds; and
	•		received proceeds of $327.8 million primarily from the sale of our Ohio tight gas sand properties.

     During 2009, we:

	•		spent $356.3 million on natural gas and oil property additions;
	•		spent $139.3 million on acreage primarily in the Marcellus Shale;
	•		received proceeds of $234.1 million primarily from the sale of West Texas and New York natural gas and oil properties; and
	•		contributed $6.4 million of capital to Nora Gathering, LLC, an equity method investment.

     During 2008, we:

	•		spent $558.0 million on natural gas and oil property additions;
	•		spent $485.3 million on acquisitions, including the purchase of Marcellus Shale leasehold;
	•		contributed $29.0 million of capital to Nora Gathering, LLC, an equity method investment; and
	•		received proceeds of $68.2 million primarily from the sale of East Texas oil and gas properties.

     Net cash provided from discontinued operations for 2010 was $79.4 million compared to $37.5 million in 2009 and $169.3 million in 2008. The increase in cash provided from discontinued operations from 2009 to 2010 reflects a 26% increase in price realizations somewhat offset by a 6% decline is production. The decrease in cash provided from discontinued operations from 2008 to 2009 reflects a 58% decrease in price realizations somewhat offset by a 27% increase in production.

     Net cash (used in) provided from financing activities in 2010 was an increase of $287.6 million compared to a decrease of $117.9 million in 2009 and an increase of $903.7 million in 2008. Historically, sources of financing have been primarily bank borrowings and capital raised through equity and debt offerings.

     During 2010, we:

	•		borrowed $1.1 billion and repaid $1.1 billion under our bank credit facility, ending the year with $50.0 million lower bank debt;
	•		issued $500.0 million aggregate principal amounts of our 6.75% senior subordinated notes due 2020; and
	•		used some of the proceeds from the sale of 6.75% senior subordinated notes to redeem all $200.0 million aggregate principal amount of our 7.375% senior subordinated notes due 2013.

     During 2009, we:

	•		borrowed $707.0 million and repaid $1.1 billion under our bank credit facility, ending the year with $369 million lower bank debt; and
	•		issued $300.0 million aggregate principal amounts of our 8% senior subordinated notes due 2019, at a discount.

     During 2008, we:

	•		borrowed $1.5 billion and repaid $1.1 billion under our bank credit facility, ending the year with $390 million higher bank debt; and
	•		issued $250.0 million aggregate principal amount of our 7.25% senior subordinated notes due 2018; and
	•		received proceeds of $282.2 million from a common stock offering.

     Net cash used in investing activities from discontinued operations for 2010 was $84.2 million compared to $184.9 million in 2009 and $673.5 million in 2008. We spent $80.2 million on natural gas and oil property additions in 2010 compared to $170.0 million in 2009 and $281.2 million in 2008. The year ended 2008 also includes $349.5 million spent on proved and unproved property acquisitions.

Cash Dividend Payments

     The amount of future dividends is subject to declaration by the Board of Directors and primarily depends on earnings, capital expenditures and various other factors. In 2010, we paid $25.6 million in dividends to our common shareholders ($0.04 per share each quarter). In 2009, we paid $25.2 million in dividends to our common shareholders ($0.04 per share in each quarter). In 2008, we paid $24.6 million in dividends to our common shareholders ($0.04 per share in each quarter).

Cash Contractual Obligations

     Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, asset retirement obligations and transportation commitments. As of December 31, 2010, we do not have any capital leases. As of December 31, 2010, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any material debt of any unrelated party. As of December 31, 2010, we had a total of $5.4 million of letters of credit outstanding under our bank credit facility. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2010. In addition to the contractual obligations listed on the table below, our balance sheet at December 31, 2010 reflects accrued interest payable on our bank debt of $1.3 million which is payable in first quarter 2011. We expect to make interest payments of $9.6 million per year on our 6.375% senior subordinated notes, $18.8 million per year on our 7.5% senior subordinated notes due 2016, $18.8 million per year on our 7.5% senior subordinated notes due 2017, $18.1 million per year on our 7.25% senior subordinated notes, $24.0 million per year on our 8% senior subordinated notes and $33.8 million per year on our 6.75% senior subordinated notes.

     The following summarizes our contractual financial obligations at December 31, 2010 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities, borrowings under our bank credit facility, additional debt issuances and proceeds from asset sales (in thousands).

		Payment due by period
														2014
		2011				2012				2013				and 2015				Thereafter				Total
Bank debt due 2012		$	—			$	274,000	(a)		$	—			$	—			$	—			$	274,000
6.375% senior subordinated notes due 2015			—				—				—				150,000				—				150,000
7.5% senior subordinated notes due 2016			—				—				—				—				250,000				250,000
7.5% senior subordinated notes due 2017			—				—				—				—				250,000				250,000
7.25% senior subordinated notes due 2018			—				—				—				—				250,000				250,000
8.0% senior subordinated notes due 2019			—				—				—				—				300,000				300,000
6.75% senior subordinated notes due 2020			—				—				—				—				500,000				500,000
Operating leases			9,676				9,826				6,917				12,763				27,833				67,015
Drilling rig commitments			72,927				53,730				14,673				896				—				142,226
Transportation commitments			61,925				61,937				61,404				120,840				381,697				687,803
Transportation commitments-discontinued operations			6,662				3,887				3,390				381				—				14,320
Other purchase obligations			50,975				42,975				2,727				—				—				96,677
Seismic agreements			11,838				6,042				645				—				—				18,525
Derivative obligations (b)			352				13,412				—				—				—				13,764
Asset retirement obligation liability (c)			4,020				8,801				522				3,255				46,075				62,673
Total contractual obligations (d)		$	218,375			$	474,610			$	90,278			$	288,135			$	2,005,605			$	3,077,003

     In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2030 to deliver natural gas production volumes in Appalachia from certain Marcellus Shale wells. The agreements call for total incremental increases of 683,000 Mmbtu per day over the 284,905 Mmbtu per day at December 31, 2010. These increases, which are contingent on certain pipeline modifications, are for 350,000 Mmbtu per day in February 2011, 150,000 Mmbtu per day in September 2011, 108,000 Mmbtu per day in November 2012 and 75,000 Mmbtu per day for November 2013.

Delivery Commitments-Discontinued Operations

     Under a sales agreement, we have an obligation to deliver 30,000 Mmbtu per day of volume at various delivery points within the Barnett Shale basin. The contract, which began in 2008, extends for five years ending March 2013. As of December 31, 2010, remaining volumes to be delivered under this commitment are approximately 24.6 Bcf.

Other

     We have agreements in place to purchase seismic data. These agreements total $11.8 million in 2011, $6.0 million in 2012 and $645,000 in 2013. We also have a two-year agreement to lease equipment, material and labor for hydraulic fracturing services for $48.0 million in 2011 and $40.0 million in 2012. We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, including the cost of infrastructure to connect production, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

Hedging — Oil and Gas Prices

     We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. We typically utilize commodity swap and collar contracts to (1) reduce the effect of price volatility on the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. In third quarter 2010, we also entered into call option derivative contracts. While there is a risk that the financial benefit of rising natural gas and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are a more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and other credit markets.

     At December 31, 2010, we had collars covering 192.8 Bcf of gas at weighted average floor and cap prices of $5.54 to $6.43 and 0.7 million barrels of oil at weighted average floor and cap prices of $70.00 to $80.00. We also have sold call options covering 3.7 millions of barrels of oil at a weighted average price of $82.31. The fair value, represented by the estimated amount that would be realized or payable on termination, based on a comparison of the contract price and a reference price, generally NYMEX, approximated a pretax gain of $118.0 million at December 31, 2010 (including $8.2 million related to discontinued operations). The contracts expire monthly through December 2012. Included in the table below for 2011 natural gas collars is 22,797 Mmbtu/day related to discontinued operations.

     At December 31, 2010, the following commodity derivative contracts were outstanding:

Period		Contract Type				Volume Hedged				Average Hedge Price
Natural Gas
2011		Collars				408,200 Mmbtu/day				$	5.56—$6.48
2012		Collars				119,641 Mmbtu/day				$	5.50—$6.25
Crude Oil
2012		Collars				2,000 bbls/day				$	70.00—$80.00
2011		Call Options				5,500 bbls/day				$	80.00
2012		Call Options				4,700 bbls/day				$	85.00

     In addition to the collars above, we have entered into basis swap agreements. The price we receive for our production can be less than NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax loss of $352,000 at December 31, 2010. These basis swaps expire first quarter 2011.

Interest Rates

     At December 31, 2010, we had $2.0 billion of debt outstanding. Of this amount, $1.7 billion bears interest at fixed rates averaging 7.2%. Bank debt totaling $274.0 million bears interest at floating rates, which averaged 2.7% at year-end 2010. The

30-day LIBOR rate on December 31, 2010 was 0.3%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2010 would cost us approximately $2.7 million in additional annual interest expense.

Off-Balance Sheet Arrangements

     We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments some of which are described above under cash contractual obligations.

Inflation and Changes in Prices

     Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas and oil prices and the costs to produce our reserves. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated through the middle of 2008, commodity prices for natural gas and oil increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends put pressure on our operating costs and also on our capital costs. Due to the decline in commodity prices that began in the last half of 2008 and continued into 2010, costs have moderated. We expect costs in 2011 to continue to be a function of supply and demand.

     The following table indicates the average natural gas and oil prices received over the last five years and quarterly for 2010, 2009 and 2008. Average price calculations exclude all derivative settlements whether or not they qualify for hedge accounting.

		Average Sales Prices (Wellhead)												Average NYMEX Prices (a)
						Crude								Natural				Crude
		Natural Gas				Oil				Equivalent Mcf				Gas				Oil
		(Per mcf)				(Per bbl)				(Per mcfe) (b)				(Per mcf)				(Per bbl)
Annual
2010		$	3.94			$	69.18			$	4.99			$	4.39			$	79.59
2009			3.60				54.94				4.44				4.02				60.48
2008			8.58				96.73				9.86				8.94				100.49
2007			6.75				67.47				7.69				6.92				72.34
2006			6.74				62.36				7.39				7.26				66.22
Quarterly
2010
First		$	5.06			$	69.62			$	5.99			$	5.37			$	78.82
Second			3.75				67.76				4.75				4.08				77.71
Third			3.86				66.74				4.73				4.42				76.18
Fourth			3.27				72.29				4.65				3.82				85.24
2009
First		$	4.16			$	38.92			$	4.45			$	4.88			$	43.20
Second			3.03				54.61				4.03				3.59				59.79
Third			3.01				63.34				4.01				3.42				68.18
Fourth			4.15				67.88				5.22				4.26				76.12
2008
First		$	8.32			$	94.57			$	9.64			$	8.07			$	97.90
Second			10.64				120.28				12.28				10.80				123.98
Third			9.86				113.91				11.37				10.09				117.86
Fourth			5.62				54.99				6.23				6.81				58.80

Management’s Discussion of Critical Accounting Estimates

     Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end, the reported amounts of revenues and expenses during the year and proved natural gas and oil reserves. Some accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results could differ from the estimates and assumptions used.

     Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.

Natural Gas and Oil Properties

     We follow the successful efforts method of accounting for natural gas and oil producing activities. Unsuccessful exploration drilling costs are expensed and can have a significant effect on reported operating results. Successful exploration drilling costs and all development costs are capitalized and systematically charged to expense using the units of production method based on proved developed natural gas and oil reserves as estimated by our engineers and reviewed by independent engineers. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our balance sheet if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Proven property leasehold costs are amortized to expense using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances warrant (at least annually) and impairments to value are charged to expense. The successful efforts method inherently relies upon the estimation of proved reserves, which includes proved developed and proved undeveloped volumes.

     Proved reserves are defined by the SEC as those volumes of natural gas, natural gas liquids, condensate and crude oil that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, including the recent rule revisions designed to modernize the oil and gas company reserves reporting requirements which we adopted effective December 31, 2009, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in natural gas and oil prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in our depletion rates. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering who reports directly to our President. For additional discussion, see “Proved Reserves,” in Item 2 of this report. To further ensure the reliability of our reserve estimates, we engage independent petroleum consultants to review our estimates of proved reserves. Independent petroleum consultants reviewed approximately 90% of our reserves in 2010 compared to 88% in 2009 and 87% in 2008. Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this report are those reserves estimated by our employees. Beginning December 31, 2009, reserve estimates are based on an average of prices in the prior 12-month period, using the closing prices on the first day of each month. In previous periods, reserve estimates were based upon prices at December 31. Neither of these prices should be expected to reflect future market conditions.

     Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the capitalized costs. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in the timing of when depletion expense is recognized. Downward revisions of proved reserves may result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion expense recognition. Based on proved reserves at December 31, 2010 (which includes our Barnett Shale assets), we estimate that a 1% change in proved reserves would increase or decrease 2011 depletion expense by approximately $12.0 million (assuming a 10% production increase). Estimated reserves are used as the basis for calculating the expected future cash flows from a property, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental

disclosure of the standardized measure of discounted future net cash flows relating to natural gas and oil producing activities and reserve quantities in Note 20 to our consolidated financial statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009 which was accounted for prospectively. We estimated the effect of this change in estimate was an increase to depletion, depreciation and amortization expense (including our Barnett Shale properties) in fourth quarter 2009 of approximately $3.4 million primarily due to lower prices reflected in our estimated reserves.

     We monitor our long-lived assets recorded in natural gas and oil properties in our consolidated balance sheets to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for natural gas and/or oil, unfavorable adjustments to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts or environmental regulations. Our natural gas and oil properties are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. All of these factors must be considered when testing a property’s carrying value for impairment. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. In certain circumstances, we also consider potential sales to properties to third parties in our estimates of future cash flows. When the carrying value exceeds the sum of future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. We cannot predict whether impairment charges may be required in the future. Our historical impairment of producing properties has been $6.5 million in 2010, $930,000 in 2009, $74.9 million in 2006, $3.6 million in 2004, $31.1 million in 2001, $29.9 million in 1999 and $214.7 million in 1998. In 2010, an impairment was recorded on our Gulf Coast properties and in 2009, an impairment was recorded on our Michigan properties due to lower reserves and natural gas prices. While our Barnett properties did not meet held for sale criteria as of December 31, 2010, our analysis reflected undiscounted cash flows for these properties were less than their carrying value. We therefore compared the carrying value of the Barnett properties to the estimated fair value of such properties and recognized an impairment charge of $463.2 million in fourth quarter 2010, which is recorded in discontinued operations. Our estimated fair value includes an estimate of the potential sales price for these properties in the estimated future cash flows. On February 28, 2011, we announced that we had entered into a definitive agreement to sell these assets along with certain derivative contracts for a price of $900.0 million, subject to typical post-closing adjustments. On April 29, 2011, we sold substantially all of these assets. We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impractical to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome.

     We are required to develop estimates of fair value to allocate purchase prices paid to acquire businesses to the assets acquired and liabilities assumed under the purchase method of accounting. The purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. We use all available information to make these fair value determinations. See Note 3 to our consolidated financial statements for information on these acquisitions.

     We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leaseholds. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Potential impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $648.1 million at December 31, 2010 compared to $572.5 million at December 31, 2009 and $485.9 million at December 31, 2008. We have recorded abandonment and impairment expense related to unproved properties of $49.7 million in 2010 compared to $36.9 million in 2009 and $15.3 million in 2008.

Natural Gas and Oil Derivatives

     All derivative instruments are recorded on our consolidated balance sheets as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. In determining the amounts to be recorded for our open hedge contracts, we are required to estimate the fair value of the derivative. Our derivatives are measured using a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes. While we remain at risk for possible changes in the market value of commodity derivatives, such risk should be mitigated by price changes in the underlying physical commodity. The determination of fair values includes various factors including the impact of our nonperformance risk on our liabilities and the credit standing of our counterparties. As of December 31, 2010, our counterparties include nine financial institutions, all of which are secured lenders in our bank credit facility.

     Through December 31, 2010, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as natural gas, NGL and oil sales when the underlying transaction occurs. If it is determined that the designated hedged transaction is not probable to occur, any unrealized gains or losses are recognized immediately in derivative fair value income in our statements of operations. During 2010, there were gains of $11.6 million compared to gains of $5.4 million in 2009 and losses of $583,000 in 2008 reclassified into earnings as a result of the discontinuance of hedge accounting treatment for our derivatives.

     We apply hedge accounting to qualifying derivatives used to manage price risk associated with our natural gas, NGL and oil production. Accordingly, we record changes in the fair value of our derivative contracts, including changes associated with time value, in accumulated other comprehensive income (“AOCI”) in the accompanying consolidated balance sheets. Gains or losses on these swap and collar contracts are reclassified out of AOCI and into natural gas, NGL and oil sales when the underlying physical transaction occurs. Any hedge ineffectiveness associated with contracts qualifying for and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period in derivative fair value income the accompanying consolidated statements of operations. Ineffectiveness can be associated with open positions (unrealized) or can be associated with closed contracts (realized).

     Realized and unrealized gains and losses on derivatives that are not designated as hedges are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in derivative fair value income in the accompanying consolidated statements of operations. We also enter into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments. Cash flows from our derivative contract settlements are reflected in cash flow provided from operating activities in the accompanying consolidated statements of cash flows.

Asset Retirement Obligations

     We have significant obligations to remove tangible equipment and restore land at the end of natural gas and oil production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future asset removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

     Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation (“ARO”), a corresponding adjustment is made to the natural gas and oil property balance. For example, as we analyze actual plugging and abandonment information, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. During 2010, we decreased our existing estimated ARO by $7.9 million or approximately 10% of the asset retirement obligation at December 31, 2009. This decrease was due to a change in the productive lives of our wells. During 2009, we increased our existing estimated asset retirement obligation by

$3.6 million or approximately 4% of the asset retirement obligation at December 31, 2008. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense, a component of depletion, depreciation and amortization in the accompanying consolidated statements of operations. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.

Deferred Taxes

     We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to audit, which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization and we must estimate our expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions and future financial conditions. The estimates are assumptions used in determining future taxable income are consistent with those used in our internal budgets and forecasts. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized.

     In determining deferred tax liabilities, accounting rules require AOCI to be considered, even though such income or loss has not yet been earned. At year-end 2010, deferred tax liabilities exceeded deferred tax assets by $683.9 million, with $43.6 million of deferred tax liabilities related to unrealized hedging gains included in accumulated other comprehensive income. At year-end 2009, deferred tax liabilities exceeded deferred tax assets by $768.9 million, with $3.8 million of deferred tax liabilities related to unrealized hedging gains included in AOCI.

     We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

     A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. Actual costs can differ from estimates for many reasons. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information. Although we continue to monitor all contingencies closely, particularly our outstanding litigation, we currently have no material accruals for contingent liabilities.

Revenue Recognition

     Natural gas, natural gas liquids and oil sales are recognized when the products are sold and delivery to the purchaser has occurred. We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered rather than our working interest share of gas produced. We recognize the cost of revenues, such as transportation and compression expense, as a reduction of revenue.

Stock-based Compensation Arrangements

     The fair value of stock options and stock-settled SARs is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We utilize historical data and analyze current information to reasonably support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of grant.

     We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period with the resulting gain or loss recognized in deferred compensation plan expense in our consolidated statement of operations.

Accounting Standards Not Yet Adopted

     In December 2010, the FASB issued ASU No. 2010-29, which updates the guidance in ASC Topic 805, Business Combinations. The objective of ASU No. 2010-29 is to address diversity in practice about the interpretation of the pro forma revenue and earnings disclosure requirements for business combinations. The amendments in ASU No. 2010-29 specify that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments also expand the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amendments affect any public entity as defined by ASC 805 that enters into business combinations that are material on an individual or aggregate basis. This guidance will become effective for us for acquisitions occurring on or after the beginning of our 2012 fiscal year. We do not expect the adoption of this guidance will have a material impact upon our financial position or results of operations.

ITEM 7A. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are US dollar denominated.

Market Risk

     We are exposed to market risks related to the volatility of natural gas, NGL and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. We are also exposed to market risks related to changes in interest rates.

Commodity Price Risk

     We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. Our derivatives program also includes collars, which establishes a minimum floor price and a predetermined ceiling price. We have also entered into call option derivative contracts under which we sold call options in exchange for a premium from the counterparty. At the time of settlement of these monthly call options, if the market price exceeds the fixed price of the call option, we will pay the counterparty such excess and if the market settle below the fixed price of the call option, no payment is due from either party. At December 31, 2010, our derivatives program includes collars and call options. As of December 31, 2010, we had collars covering 192.8 Bcf of gas and 0.7 million barrels of oil. We also have sold call options covering 3.7 million barrels of oil. These contracts expire monthly through December 2012. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of December 31, 2010, approximated a net unrealized pre-tax gain of $118.0 million (including $8.2 million related to discontinued operations) compared to a gain of $28.7 million at December 31, 2009. This change is primarily related to the expiration of natural gas and oil derivative contracts during 2010 and to the natural gas and oil futures prices as of December 31, 2010, in relation to the new commodity derivative contracts we entered into during 2010 for 2011 and 2012. Included in the table below for 2011 natural gas collars is 22,797 Mmbtu/day related to discontinued operations.

At December 31, 2010, the following commodity derivative contracts were outstanding:

										Average				Fair
Period		Contract Type				Volume Hedged				Hedge Price				Market Value
														(in thousands)
Natural Gas
2011		Collars				408,200 Mmbtu/day				$	5.56—$6.48			$	163,354
2012		Collars				119,641 Mmbtu/day				$	5.50—$6.25			$	27,032
Crude Oil
2012		Collars				2,000 bbls/day				$	70.00—$80.00			$	(12,052	)
2011		Call options				5,500 bbls/day				$	80.00			$	(31,904	)
2012		Call options				4,700 bbls/day				$	85.00			$	(28,393	)

     We expect our NGL production to continue to increase. We currently have not entered into any NGL derivative contracts. In our Marcellus Shale operations, propane is a large product component of our NGL production and we believe NGL prices are somewhat seasonal. Therefore, the percentage of NGL prices to NTMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand.

Other Commodity Risk

     We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased basis risk. In addition to the collars and call options above, we have entered into basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net realized pre-tax loss of $352,000 at December 31, 2010. These basis swaps expire in first quarter 2011.

     The following table shows the fair value of our collars and call options and the hypothetical change in fair value that would result from a 10% and a 25% change in commodity prices at December 31, 2010. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity (in thousands):

						Hypothetical Change								Hypothetical Change
						in Fair Value								in Fair Value
						Increase of								Decrease of
		Fair Value				10%				25%				10%				25%
Collars		$	178,335			$	(82,083	)		$	(199,536	)		$	85,644			$	219,992
Call options			(60,297	)			(27,711	)			(73,471	)			23,800				47,432

     Our commodity-based contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified among major investment grade financial institutions and we have master netting agreements with the majority of our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At December 31, 2010, our derivative counterparties include nine financial institutions, all of which are secured lenders in our bank credit facility. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While counterparties are major investment grade financial institutions, the fair value of our derivative contracts have been adjusted to account for the risk of non-performance by counterparty, which was immaterial.

Interest Rate Risk

     We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate senior subordinated debt and variable rate bank debt. At December 31, 2010, we had $2.0 billion of debt outstanding. Of this amount, $1.7 billion bears interest at a fixed rate averaging 7.2%. Bank debt totaling $274.0 million bears interest at floating rates, which was 2.7% on that date. On December 31, 2010, the 30-day LIBOR rate was 0.3%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2010 would cost us approximately $2.7 million in additional annual interest expense.

     The fair value of our subordinated debt is based on year-end quoted market prices. The following table presents information on these fair values (in thousands):

		Carrying Value				Fair Value
Fixed rate debt:
Senior Subordinated Notes due 2015 (The interest rate is fixed at a rate of 6.375%)		$	150,000			$	153,000
Senior Subordinated Notes due 2016 (The interest rate is fixed at a rate of 7.5%)			249,683				259,375
Senior Subordinated Notes due 2017 (The interest rate is fixed at a rate of 7.5%)			250,000				263,438
Senior Subordinated Notes due 2018 (The interest rate is fixed at a rate of 7.25%)			250,000				263,750
Senior Subordinated Notes due 2019 (The interest rate is fixed at a rate of 8.0%)			286,853				326,625
Senior Subordinated Notes due 2020 (The interest rate is fixed at a rate of 6.75%)			500,000				515,625
		$	1,686,536			$	1,781,813

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     For financial statements required by Item 8, see Item 15 in Part IV of this report.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     None.

ITEM 9A. CONTROLS AND PROCEDURES

     Evaluation of Disclosure Controls and Procedures. As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective as of December 31, 2010.

     Management’s Annual Report on Internal Control over Financial Reporting and Attestation Report of Registered Public Accounting Firm. Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, we have included a report of management’s assessment of the design and effectiveness of its internal controls as part of this Annual Report on Form 10-K for the fiscal year ended December 31, 2010. Ernst & Young LLP, our registered public accountants, also attested to, and reported on, the effectiveness of internal control over financial reporting. Management’s report and the independent public accounting firm’s attestation report are included in our 2010 Financial Statements in Item 15 under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting,” and are incorporated herein by reference.

     Changes in Internal Control over Financial Reporting. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during fourth quarter 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting or in other factors that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

     None.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

Documents filed as part of the report:

1.

Financial Statements:

		Page
		Number
Index to Financial Statements			F- 1
Report of Independent Registered Public Accounting Firm — Consolidated Financial Statements			F- 2
Consolidated Balance Sheets as of December 31, 2010 and 2009			F- 3
Consolidated Statements of Operations for the Year Ended December 31, 2010, 2009 and 2008			F- 4
Consolidated Statements of Cash Flows for the Year Ended December 31, 2010, 2009 and 2008			F- 5
Consolidated Statements of Stockholders’ Equity for the Year Ended December 31, 2010, 2009 and 2008			F- 6
Consolidated Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2010, 2009 and 2008			F- 7
Notes to Consolidated Financial Statements			F- 8
Selected Quarterly Financial Data (Unaudited)			F- 35
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)			F- 37

2.		All other schedules are omitted because they are not applicable, not required, or because the required information is included in the financial statements or related notes.
3.		Exhibits:

(a)

See Index of Exhibits on page 29 for a description of the exhibits filed as a part of this report.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Range Resources Corporation:

     We have audited the accompanying consolidated balance sheets of Range Resources Corporation (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity, comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Range Resources Corporation at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

     As discussed in Note 19 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of the 2009 adoption of new oil and gas reserve estimation and disclosure requirements.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Range Resources Corporation’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2011 expressed an unqualified opinion thereon.

Fort Worth, Texas
March 1, 2011, except for Note 4 as to which the date is May 6, 2011.

RANGE RESOURCES CORPORATION

		December 31,
		2010				2009
Assets
Current assets:
Cash and cash equivalents		$	2,848			$	767
Accounts receivable, less allowance for doubtful accounts of $5,001 and $2,176			76,683				80,694
Assets of discontinued operations			876,304				43,481
Deferred tax asset			—				8,054
Unrealized derivative gain			123,255				21,544
Inventory and other			21,352				20,740
Total current assets			1,100,442				175,280
Unrealized derivative gain			—				4,107
Equity method investments			155,105				146,809
Natural gas and oil properties, successful efforts method			5,390,391				4,716,478
Accumulated depletion and depreciation			(1,306,378	)			(1,164,843	)
			4,084,013				3,551,635
Transportation and field assets			134,980				159,926
Accumulated depreciation and amortization			(60,931	)			(68,886	)
			74,049				91,040
Assets of discontinued operations			—				1,347,979
Other assets			84,977				79,031
Total assets		$	5,498,586			$	5,395,881
Liabilities
Current liabilities:
Accounts payable		$	289,109			$	191,355
Asset retirement obligations			4,020				2,001
Accrued liabilities			60,082				48,838
Liabilities of discontinued operations			32,962				33,385
Deferred tax liability			11,848				—
Accrued interest			32,189				24,037
Unrealized derivative loss			352				14,488
Total current liabilities			430,562				314,104
Bank debt			274,000				324,000
Subordinated notes			1,686,536				1,383,833
Deferred tax liability			672,041				776,965
Unrealized derivative loss			13,412				271
Liabilities of discontinued operations			3,901				4,564
Deferred compensation liability			134,488				135,541
Asset retirement obligations and other liabilities			59,885				78,014
Total liabilities			3,274,825				3,017,292
Commitments and contingencies
Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding			—				—
Common stock, $0.01 par, 475,000,000 shares authorized, 160,113,608 issued at December 31, 2010 and 158,336,264 issued at December 31, 2009			1,601				1,583
Common stock held in treasury, 204,556 shares at December 31, 2010 and 217,327 shares at December 31, 2009			(7,512	)			(7,964	)
Additional paid-in capital			1,820,503				1,772,020
Retained earnings			341,699				606,529
Accumulated other comprehensive income			67,470				6,421
Total stockholders’ equity			2,223,761				2,378,589
Total liabilities and stockholders’ equity		$	5,498,586			$	5,395,881