UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	04-3072771
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification Number)

Three Memorial City Plaza 840 Gessner Road, Suite 1400 Houston, Texas 77024

(Address of principal executive offices including ZIP code)

(281) 589-4600

(Registrant’s telephone number, including area code)

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

Title of each class	Name of each exchange on which registered
Common Stock, par value $.10 per share	New York Stock Exchange

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes x    No ¨

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

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

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

(Do not check if a smaller reporting company)

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

The aggregate market value of Common Stock, par value $.10 per share (“Common Stock”), held by non-affiliates as of the last business day of registrant’s most recently completed second fiscal quarter (based upon the closing sales price on the New York Stock Exchange on June 30, 2010) was approximately $3.3 billion.

As of February 18, 2011, there were 104,277,128 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 3, 2011 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

PART I		PAGE
ITEM 1	Business		4
ITEM 1A	Risk Factors		20
ITEM 1B	Unresolved Staff Comments		28
ITEM 2	Properties		28
ITEM 3	Legal Proceedings		28
	Executive Officers of the Registrant		30
PART II
ITEM 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		31
ITEM 6	Selected Financial Data		33
ITEM  7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33
ITEM 7A	Quantitative and Qualitative Disclosures about Market Risk		51
ITEM 8	Financial Statements and Supplementary Data		54
ITEM 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		111
ITEM 9A	Controls and Procedures		111
ITEM 9B	Other Information		111
PART III
ITEM 10	Directors, Executive Officers and Corporate Governance		112
ITEM 11	Executive Compensation		112
ITEM 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		112
ITEM 13	Certain Relationships and Related Transactions, and Director Independence		112
ITEM 14	Principal Accountant Fees and Services		112
PART IV
ITEM 15	Exhibits and Financial Statement Schedules		112

The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives and other factors detailed in this document and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and uncertainties. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document. See “Forward-Looking Information” for further details.

GLOSSARY OF CERTAIN OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and included within this Annual Report on Form 10-K:

Abbreviations

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet of natural gas equivalent.

Mbbls. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet of natural gas equivalent.

Mmbtu. One million British thermal units.

Mmcf. One million cubic feet of natural gas.

Mmcfe. One million cubic feet of natural gas equivalent.

NGL. Natural gas liquids.

NYMEX. New York Mercantile Exchange.

Definitions

Developed reserves. Developed reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or gas from an established spot market price to reflect differences in the quality and/or location of oil or gas.

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Dry Hole. Exploratory or development well that does not produce oil or gas in commercial quantities.

Exploitation activities. The process of the recovery of fluids from reservoirs and drilling and development of oil and gas properties.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, or a service well.

Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geological barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Oil. Crude oil and condensate.

Operator. The individual or company responsible for the exploration and/or production of an oil or gas well or lease.

Proved reserves. Proved reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions and operating methods prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Recompletion. An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure. The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of future price changes to the extent

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provided by contractual arrangements in existence at year-end), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on year-end costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the appropriate year-end statutory federal and state income tax rate with consideration of future tax rates already legislated, to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and gas reserves.

Undeveloped reserves. Undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

The terms “developed reserves”, “development well”, “exploratory well”, “extension well”, “field”, “proved reserves”, “reserves”, “reservoir” and “undeveloped reserves” are defined by the SEC.

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PART I

ITEM 1. BUSINESS

OVERVIEW

Cabot Oil & Gas Corporation is an independent oil and gas company engaged in the development, exploitation and exploration of oil and gas properties located in the United States. In 2009, we restructured our operations by combining our Rocky Mountain and Appalachian areas to form the North region and combining the Anadarko Basin with our Texas and Louisiana areas to form the South region. Certain prior period amounts and historical descriptions have been reclassified to reflect this reorganization. Operationally, we now have two primary regional offices located in Houston, Texas and Pittsburgh, Pennsylvania.

In 2010, natural gas prices decreased from the price levels experienced during 2009, while crude oil prices increased. Our 2010 average realized natural gas price was $5.54 per Mcf, 26% lower than the 2009 average realized price of $7.47 per Mcf. Our 2010 average realized crude oil price was $97.91 per Bbl, 14% higher than the 2009 average realized price of $85.52 per Bbl. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” section in Item 7 of this Annual Report on Form 10-K.

In 2010, our investment program totaled $891.5 million, including lease acquisition ($130.7 million) and drilling and facilities ($654.2 million) programs. Our capital spending was funded through cash on hand, operating cash flow, borrowings on our revolving credit facility, proceeds from our new senior notes offering and select asset sales.

We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure sufficient liquidity, including cash resources and available credit. We believe these strategies are appropriate for our portfolio of projects and the current industry environment and will continue to add shareholder value over the long-term.

In December 2010, we sold our existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations to Williams Field Services (Williams), a subsidiary of Williams Partners L.P., for $150 million and recognized a $49.3 million gain on sale of assets. Under the terms of the purchase and sale agreement, we are obligated to construct pipelines to connect certain of our 2010 program wells, complete the construction of the Lathrop compressor station and complete taps into certain pipeline delivery points. We expect to complete these obligations in the first half of 2011. We also entered into a 25-year firm gathering contract with Williams that requires Williams to complete construction of approximately 32 miles of high pressure pipeline, 65 miles of trunklines in Susquehanna County, and build two compressor stations in the next two years. Additionally, Williams will connect all of our drilling program wells, which will connect our production to five interstate pipeline delivery options.

In addition, in December 2010 we closed a private placement of $175 million principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 5.58%.

In September 2010, we amended and restated our revolving credit facility to increase the available credit line to $900 million and with an accordion feature allowing us to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. The amended facility provides for a $1.5 billion borrowing base and extends the term of the agreement to September 2015.

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In April 2009, we sold substantially all of our Canadian properties to Tourmaline Oil Corporation (Tourmaline) in exchange for cash and common stock shares of Tourmaline. In November 2010, we sold our investment in Tourmaline for $61.3 million and recognized a $40.7 million gain on sale of assets.

In 2010, we sold various other properties for total proceeds of $30.4 million and an aggregate gain of $15.3 million.

In August 2008, we completed the acquisition of producing properties, leasehold acreage and a natural gas gathering infrastructure in east Texas (the “east Texas acquisition”). We paid total net cash consideration of approximately $604.0 million. In order to finance the east Texas acquisition, we completed a public offering of 5,002,500 shares of our common stock in June 2008, receiving net proceeds of $313.5 million, and we closed a private placement in July 2008 of $425 million principal amount of 6.51% weighted average senior unsecured fixed rate notes.

On an equivalent basis, our production level in 2010 increased by 27% from 2009. We produced 130.6 Bcfe, or 357.9 Mmcfe per day, in 2010, as compared to 103.0 Bcfe, or 282.1 Mmcfe per day, in 2009. Natural gas production increased to 125.5 Bcf in 2010 from 97.9 Bcf in 2009, primarily due to increased production in the North region associated with the increased drilling program and the Lathrop compressor station in Susquehanna County, Pennsylvania. The decline in the other areas is related to natural production decline. Oil production decreased by 10 Mbbls from 818 Mbbls in 2009 to 808 Mbbls in 2010 due primarily to a decrease in production in the North and a decrease in production in Canada due to the sale of our Canadian properties in April 2009, partially offset by increased production in the South region associated with the Eagle Ford shale and Pettet formation production.

For the year ended December 31, 2010, we drilled 113 gross wells (87.1 net) with a success rate of 98% compared to 143 gross wells (118.6 net) with a success rate of 95% for the prior year. In 2011, we plan to drill approximately 110 gross wells (83.1 net), focusing our capital program in the Marcellus shale in northeast Pennsylvania and the Eagle Ford shale in south Texas.

Our 2010 total capital and exploration spending was $891.5 million compared to $640.4 million in 2009. In both 2010 and 2009, we allocated our planned program for capital and exploration expenditures among our various operating regions based on return expectations, availability of services and human resources. We plan to continue such method of allocation in 2011. Funding of the program is expected to be provided by operating cash flow, existing cash and, if required, borrowings under our credit facility. For 2011, the North region is expected to receive approximately 58% of the anticipated capital program, with the remaining 42% dedicated to the South region. In 2011, we plan to spend approximately $600 million on capital and exploration activities.

Our proved reserves totaled approximately 2,701 Bcfe at December 31, 2010, of which 98% were natural gas. This reserve level was up by 31% from 2,060 Bcfe at December 31, 2009 on the strength of results from our drilling program. In 2010, we had a net upward revision of 136.7 Bcfe, which was primarily due to an upward performance revision of 284.4 Bcfe, primarily in the Dimock field in northeast Pennsylvania, and an upward revision of 35.0 Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of 182.7 Bcfe (115.1 Bcfe in the North region and 67.6 Bcfe in the South region) of proved undeveloped reserves that are no longer in our five-year development plan.

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The following table presents certain reserve, production and well information as of December 31, 2010.

	North			South			Total
Proved Reserves at Year End (Bcfe)
Developed.		1,251.3			472.9			1,724.2
Undeveloped		755.9			221.0			976.9
Total		2,007.2			693.9			2,701.1
Average Daily Production (Mmcfe per day)		223.5			134.4			357.9
Reserve Life Index (In years)(1)		24.6			14.1			20.7
Gross Wells		4,185			1,769			5,954
Net Wells(2)		3,588.5			1,231.1			4,819.6
Percent Wells Operated (Gross)		89.0	%		76.0	%		85.1	%

⁽¹⁾ Reserve Life Index is equal to year-end reserves divided by annual production.

⁽²⁾ The term “net” as used in “net acreage” or “net production” throughout this document refers to amounts that include only acreage or production that is owned by us and produced to our interest, less royalties and production due others. “Net wells” represents our working interest share of each well.

Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right, in general, to develop oil and/or natural gas on the properties. Their primary terms range in length from approximately three to ten years. These properties are held for longer periods if production is established. We own leasehold rights on approximately 2.3 million gross acres. In addition, we own fee interest in approximately 0.2 million gross acres, primarily in West Virginia. Our largest field (Dimock), which is our only field that contains more than 15% of our proved reserves, is located in northeast Pennsylvania. This field makes up approximately 46% of our proved reserves.

The following table presents certain information with respect to our Dimock field:

	Year Ended December 31,
	2010		2009		2008
Production:
Natural gas (Bcf)		49.5		36.3		0.6
Crude oil and condensate (Mbbls)		—		—		—
Produced Sales Price:(1)
Natural gas ($/Mcf)	$	4.48	$	4.19	$	7.28
Crude oil and condensate ($/Bbl)	$	—	$	—	$	—
Production Cost ($/Mcfe):	$	0.08	$	0.03	$	0.01

⁽¹⁾ Excludes realized impact of derivative instruments.

NORTH REGION

The North region is comprised of the Appalachian and Rocky Mountains areas. Our activities in the Appalachian area are concentrated primarily in northeast Pennsylvania and in West Virginia. Our activities in the Rocky Mountains area are concentrated in the Green River and Washakie Basins in Wyoming. This region is managed from our office in Pittsburgh, Pennsylvania. In this region, our assets include a large acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity. In December 2010, we sold our existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations. In July 2010, we sold our properties in the Paradox Basin in Colorado.

Capital and exploration expenditures for 2010 were $603.6 million, or 68% of our total 2010 capital and exploration expenditures, compared to $380.3 million for 2009, or 60% of our total 2009 capital and exploration

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expenditures. This increase in spending was substantially driven by an expanded Marcellus horizontal drilling program in northeast Pennsylvania to hold acreage. For 2011, we have budgeted approximately $350.0 million for capital and exploration expenditures in the region.

At December 31, 2010, we had 4,185 wells (3,588.5 net), of which 3,724 wells are operated by us. There are multiple producing intervals in the Appalachian area that includes the Big Lime, Weir, Berea and Devonian (including Marcellus) shale formations at depths primarily ranging from 950 to 7,800 feet, with an average depth of approximately 4,050 feet. In the Rocky Mountains area, principal producing intervals are in the Almond, Frontier and Dakota formations at depths ranging from 8,100 to 14,375 feet, with an average depth of approximately 11,050 feet.

Natural gas production and reserves in the North region are primarily associated with the Marcellus shale. At December 31, 2010, we had 2,007.2 Bcfe of proved reserves (substantially all natural gas) in the North region, constituting 74% of our total proved reserves. Developed and undeveloped reserves made up 1,251.3 Bcfe and 755.9 Bcfe of the total proved reserves for the North region, respectively.

In 2010, we drilled 63 wells (61.3 net) in the North region, of which 62 wells (60.3 net) were development and extension wells. In 2011, we plan to drill approximately 54 wells (54.0 net), primarily in the Dimock field in northeast Pennsylvania.

In 2010, we produced and marketed approximately 221.8 Mmcf per day of natural gas and 272.5 barrels of crude oil/condensate/NGL per day in the North region at market responsive prices. Average daily production in 2010 was 223.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2010 was 81.0 Bcf and 100 Mbbls, respectively.

Ancillary to our exploration, development and production operations, we operated a number of gas gathering and transmission pipeline systems, made up of approximately 3,148 miles of pipeline with interconnects to three interstate transmission systems and seven local distribution companies and numerous end users as of the end of 2010. The majority of our pipeline infrastructure in West Virginia is regulated by the Federal Energy Regulatory Commission (FERC) for interstate transportation service and the West Virginia Public Service Commission (WVPSC) for intrastate transportation service. As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC and the WVPSC. Our natural gas gathering and transmission pipeline systems in West Virginia enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system.

We have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas and the higher prices typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The storage fields also enable us to increase for shorter intervals of time the volume of natural gas that we can deliver by more than 40% above the volume that we could deliver solely from our production in the North region. The pipeline systems and storage fields are fully integrated with our operations.

The principal markets for our North region natural gas are in the northeastern and northwestern United States. We sell natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system. Approximately 42% of our natural gas sales volume in the North region is sold at index-based prices under contracts with terms of one year or greater. The remaining 58% of our natural gas sales volume is sold under contracts with terms less than one year. Spot market sales are made at index-based prices under month-to-month contracts, while industrial and utility sales generally are made under year-to-year contracts.

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SOUTH REGION

Our development, exploitation, exploration and production activities in the South region are primarily concentrated in east and south Texas and Oklahoma. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley, Haynesville, Bossier, and James Lime formations in east Texas, the Eagle Ford, Frio, Vicksburg and Wilcox formations in south Texas and the Chase, Morrow and Chester formations in the Anadarko Basin in Oklahoma at measured depths ranging from approximately 2,500 to 17,700 feet, with an average depth of approximately 8,950 feet. We sold our Woodford shale prospect located in Oklahoma in June 2010 and certain oil and gas properties in the Texas panhandle in November 2010.

Capital and exploration expenditures were $280.4 million for 2010, or 32% of our total 2010 capital and exploration expenditures, compared to $237.6 million for 2009, or 37% of our total 2009 capital and exploration expenditures. This increase in capital spending is primarily due to lease acquisitions to establish a greater position in the oil window of the Eagle Ford shale. For 2011, we have budgeted approximately $250 million for capital and exploration expenditures in the region. Our 2011 South region drilling program will emphasize activity primarily in the Eagle Ford shale in south Texas.

We had 1,769 wells (1,231.1 net) in the South region as of December 31, 2010, of which 1,345 wells are operated by us. Average daily production in 2010 was 134.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2010 was 44.5 Bcf and 759 Mbbls, respectively.

At December 31, 2010, we had 693.9 Bcfe of proved reserves (93% natural gas) in the South region, which represented 26% of our total proved reserves. Developed and undeveloped reserves made up 472.9 Bcfe and 221.0 Bcfe of the total proved reserves for the South region, respectively.

In 2010, we drilled 50 wells (25.8 net) in the South region, of which 47 wells (23.3 net) were development and extension wells. In 2011, we plan to drill 56 wells (29.1 net), primarily in the Eagle Ford shale in south Texas.

Our principal markets for the South region natural gas are in the industrialized Gulf Coast area and the Midwestern United States. We sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Currently, approximately 83% of our natural gas sales volumes in the South region are sold at index-based prices under contracts with terms of one year or greater. The remaining 17% of our natural gas sales volumes are sold at index-based prices under short-term agreements. The South region properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.

In 2010, we produced and marketed approximately 122.0 Mmcf per day of natural gas and 2,079.1 barrels of crude oil/condensate/NGL per day in the South region at market responsive prices. Average daily production in 2010 was 134.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2010 was 44.5 Bcf and 759 Mbbls, respectively.

RISK MANAGEMENT

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 2010 we employed natural gas and crude oil swap agreements for portions of our 2010 production to attempt to manage price risk more effectively. During 2010, we also entered into crude oil swaps to hedge our price exposure on our 2010 production, natural gas swaps to hedge our price exposure on our 2011 production and crude oil price collars to hedge our price exposure on our 2011 production. In addition, we also have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting. In 2009 and 2008, we employed price collars and swaps to hedge our price exposure on our production.

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The collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place.

For 2010, swaps covered 29% of natural gas production and 90% of crude oil production and had a weighted-average price of $9.30 per Mcf and $104.25 per Bbl, respectively.

As of December 31, 2010, we had the following outstanding commodity derivatives:

Commodity and Derivative Type	Weighted-Average Contract Price	Volume		Contract Period
Derivatives Designated as Hedging Instruments
Natural Gas Swaps	$6.24 per Mcf		12,909 Mmcf		January - December 2011
Crude Oil Collars	$93.25 Ceiling /$80.00 Floor per Bbl		365 Mbbl		January - December 2011
Derivatives Not Designated as Hedging Instruments
Natural Gas Basis Swaps	$(0.27) per Mcf		16,123 Mmcf		January - December 2012

We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk” for further discussion concerning our use of derivatives.

RESERVES

Current Reserves

The following table presents our estimated proved reserves at December 31, 2010.

	Natural  Gas (Mmcf)		Liquids(1) (Mbbl)		Total(2) (Mmcfe)
Developed:
North		1,243,051		1,373		1,251,289
South		438,400		5,756		472,936
Undeveloped:
North		755,767		22		755,899
South		206,940		2,340		220,978
Total		2,644,158		9,491		2,701,102

⁽¹⁾ Liquids include crude oil, condensate and natural gas liquids.

⁽²⁾ Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.

Our reserve estimates were based on decline curve extrapolations, material balance calculations, analogies, or combinations of these methods for each well.

The proved reserve estimates presented herein were prepared by our petroleum engineering staff and audited by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents made independent estimates for 100% of the proved reserves estimated by us and concluded the following: In their judgment we have an effective system for gathering data and documenting information required to estimate our proved reserves and

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project our future revenues. Further, Miller and Lents has concluded (1) the reserves estimation methods employed by us were appropriate, and our classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) our reserves estimation processes were comprehensive and of sufficient depth, (3) the data upon which we relied were adequate and of sufficient quality, and (4) the results of our estimates and projections are, in the aggregate, reasonable. For additional information regarding estimates of proved reserves, the audit of such estimates by Miller and Lents, Ltd., and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. A copy of the audit letter by Miller and Lents, Ltd., dated February 1, 2011, has been filed as an exhibit to this Form 10-K. Our reserves are sensitive to natural gas and crude oil sales prices and their effect on the economic productive life of producing properties. Our reserves are based on 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during 2010. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in prices may result in negative impacts of this nature.

Internal Control

Our corporate reservoir engineers report to the Director of Engineering, who maintains oversight and compliance responsibility for the internal reserve estimation process and provides oversight for the annual audit of our year-end reserves by our independent third party engineers, Miller and Lents, Ltd. Our corporate reservoir engineering group consists of two petroleum/chemical engineers, with petroleum/chemical engineering degrees and between 11 and 28 years of industry experience, between four and 28 years of reservoir engineering/management experience, and between three and 12 years managing our reserves. Both are members of the Society of Petroleum Engineers.

Qualifications of Third Party Engineers

The technical person primarily responsible for audit of our reserve estimates at Miller and Lents, Ltd. meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents, Ltd. is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

For additional information about the risks inherent in our estimates of proved reserves, see “Risk Factors—Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

Proved Undeveloped Reserves

At December 31, 2010, we had 976.9 Bcfe of proved undeveloped reserves, which represents an increase of 241.7 Bcfe compared with December 31, 2009. For 2010, total capital related to the development of proved undeveloped reserves was $183.4 million, resulting in the conversion of 216.9 Bcfe of reserves to proved developed. During 2010, we had 391.8 Bcfe of proved undeveloped reserve additions and 249.5 Bcfe of positive proved undeveloped reserve performance revisions, primarily in the Dimock field in northeast Pennsylvania. Lastly, we removed 182.7 Bcfe (115.1 Bcfe in the North region and 67.6 Bcfe in the South region) of proved undeveloped reserves associated with drilling locations no longer anticipated to be developed within the next five years.

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Historical Reserves

The following table presents our estimated proved reserves for the periods indicated.

	Natural  Gas (Mmcf)			Oil &  Liquids (Mbbl)			Total (Mmcfe)(1)
December 31, 2007(5)		1,559,953			9,328			1,615,919
Revision of Prior Estimates(2)		(47,745	)		(1,593	)		(57,302	)
Extensions, Discoveries and Other Additions		297,089			1,134			303,895
Production.		(90,425	)		(794	)		(95,191	)
Purchases of Reserves in Place		167,262			1,268			174,872
Sales of Reserves in Place		(141	)		(2	)		(156	)
December 31, 2008(5)		1,885,993			9,341			1,942,037
Revision of Prior Estimates(3)		(193,767	)		(1,062	)		(200,143	)
Extensions, Discoveries and Other Additions		459,612			544			462,880
Production		(97,914	)		(844	)		(102,976	)
Purchases of Reserves in Place		9			—			9
Sales of Reserves in Place		(40,771	)		(196	)		(41,949	)
December 31, 2009		2,013,162			7,783			2,059,858
Revision of Prior Estimates(4)		139,016			(379	)		136,742
Extensions, Discoveries and Other Additions		632,980			2,944			650,644
Production		(125,474	)		(858	)		(130,622	)
Purchases of Reserves in Place		593			4			617
Sales of Reserves in Place		(16,119	)		(3	)		(16,137	)
December 31, 2010		2,644,158			9,491			2,701,102
Proved Developed Reserves
December 31, 2007		1,133,937			7,026			1,176,091
December 31, 2008		1,308,155			6,728			1,348,521
December 31, 2009		1,288,169			6,082			1,324,663
December 31, 2010		1,681,451			7,129			1,724,225
Proved Undeveloped Reserves
December 31, 2007		426,016			2,302			439,828
December 31, 2008		577,838			2,613			593,516
December 31, 2009		724,993			1,701			735,199
December 31, 2010		962,707			2,362			976,877

⁽¹⁾ Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.

⁽²⁾ The majority of the revisions were the result of the decrease in the natural gas price.

⁽³⁾ The net downward revision of 200.1 Bcfe was primarily due to (i) downward revisions of 101.6 Bcfe due to lower 2009 oil and natural gas prices compared to 2008 and (ii) downward revisions of 120.4 Bcfe due to the removal of proved undeveloped reserves scheduled for development beyond five years primarily due to the application of the SEC’s oil and gas reserve calculation methodology effective beginning in 2009, partially offset by 21.9 Bcfe of positive performance revisions.

⁽⁴⁾ The net upward revision of 136.7 Bcfe was primarily due to (i) an upward performance revision of 284.4 Bcfe, primarily in the Dimock field in northeast Pennsylvania, and (ii) an upward revision of 35.0 Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of 182.7 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.

⁽⁵⁾ Prior to 2009, reserve estimates were based on year end prices.

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Production and Sales

The following table presents regional historical information about our net wellhead sales volume for natural gas and crude oil (including condensate and natural gas liquids), produced natural gas and crude oil realized sales prices, and production costs per equivalent.

	Year Ended December 31,
	2010		2009		2008
Net Wellhead Sales Volume
Natural Gas (Bcf)
North		81.0		48.2		39.7
South		44.5		48.8		46.6
Canada(3)		—		1.0		4.1
Crude/Condensate/Ngl (Mbbl)
North		100		118		118
South		759		720		655
Canada(3)		—		7		21
Equivalents (Bcfe)
North		81.6		48.9		40.4
South		49.1		53.1		50.5
Canada(3)		—		1.0		4.3
Produced Natural Gas Sales Price ($/Mcf)(1)
North	$	4.59	$	6.59	$	7.95
South		7.26		8.42		8.84
Canada(3)		—		3.72		7.62
Weighted-Average		5.54		7.47		8.39
Produced Crude/Condensate Sales Price ($/Bbl)(1)
North	$	69.31	$	54.11	$	93.62
South		101.65		90.86		88.46
Canada(3)		—		33.97		85.08
Weighted-Average		97.91		85.52		89.11
Production Costs ($/Mcfe)(2)
North	$	0.45	$	0.67	$	0.80
South		0.93		0.78		0.76
Canada(3)		—		1.55		0.88
Weighted-Average		0.63		0.74		0.78

⁽¹⁾ Represents the average realized sales price for all production volumes and royalty volumes sold during the periods shown, net of related costs (principally purchased gas royalty, transportation and storage). Includes realized impact of derivative instruments.

⁽²⁾ Production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), the costs of administration of production offices and insurance, but is exclusive of depreciation and depletion applicable to capitalized lease acquisition, exploration and development expenditures and taxes other than income.

⁽³⁾ In April 2009, we sold substantially all of our Canadian properties.

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Acreage

The following tables summarize our gross and net developed and undeveloped leasehold and mineral fee acreage by region at December 31, 2010. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

	Developed				Undeveloped				Total
	Gross		Net		Gross		Net		Gross		Net
Leasehold Acreage
North		887,288		731,211		763,389		612,178		1,650,677		1,343,389
South		389,905		290,436		274,800		205,893		664,705		496,329
Total		1,277,193		1,021,647		1,038,189		818,071		2,315,382		1,839,718
Mineral Fee Acreage
North		116,674		97,992		62,651		51,819		179,325		149,811
South		16,947		14,242		1,892		690		18,839		14,932
Total		133,621		112,234		64,543		52,509		198,164		164,743
Aggregate Total		1,410,814		1,133,881		1,102,732		870,580		2,513,546		2,004,461

Total Net Undeveloped Acreage Expiration

The following table presents our net undeveloped acreage expiring over the next three years by region as of December 31, 2010. The figures below assume no future successful development or renewal of undeveloped acreage.

	2011		2012		2013
North		142,999		121,146		160,554
South		89,528		39,621		36,768
Total		232,527		160,767		197,322

Well Summary

The following table presents our ownership in productive natural gas and oil wells by region at December 31, 2010. This summary includes natural gas and oil wells in which we have a working interest.

	Natural Gas				Oil				Total(1)
	Gross		Net		Gross		Net		Gross		Net
North		4,130		3,552.4		36		18.1		4,166		3,570.5
South		1,571		1,060.4		162		136.4		1,733		1,196.8
Total		5,701		4,612.8		198		154.5		5,899		4,767.3

⁽¹⁾ Total excludes 55 (52.3 net) service wells.

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Drilling Activity

We drilled wells, participated in the drilling of wells, or acquired wells as indicated in the tables below.

	Year Ended December 31, 2010
	North				South				Total
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		57		55.3		39		19.0		96		74.3
Dry		—		—		1		1.0		1		1.0
Extension Wells
Productive		5		5.0		7		3.3		12		8.3
Dry		—		—		—		—		—		—
Exploratory Wells
Productive		—		—		3		2.5		3		2.5
Dry		1		1.0		—		—		1		1.0
Total		63		61.3		50		25.8		113		87.1
Wells Acquired		—		—		—		—		—		—
Wells in Progress at End of Year		7		6.0		7		4.2		14		10.3
	Year Ended December 31, 2009 (1)
	North				South				Total
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		53		51.3		71		52.3		124		103.6
Dry		1		1.0		4		3.0		5		4.0
Extension Wells
Productive		7		7.0		—		—		7		7.0
Dry		—		—		—		—		—		—
Exploratory Wells
Productive		1		0.1		4		2.4		5		2.5
Dry		—		—		2		1.5		2		1.5
Total		62		59.4		81		59.2		143		118.6
Wells Acquired		—		—		1		1.0		1		1.0

⁽¹⁾ In April 2009, we sold substantially all of our Canadian properties.

	Year Ended December 31, 2008
	North				South				Canada				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		250		227.2		145		99.7		3		2.0		398		328.9
Dry		1		1.0		7		6.3		1		0.6		9		7.9
Extension Wells
Productive		3		3.0		2		1.7		—		—		5		4.7
Dry		1		1.0		—		—		—		—		1		1.0
Exploratory Wells
Productive		3		3.0		11		6.8		2		0.8		16		10.6
Dry		3		1.5		—		—		—		—		3		1.5
Total		261		236.7		165		114.5		6		3.4		432		354.6
Wells Acquired		—		—		70		68.3		—		—		70		68.3

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Competition

Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times and distribution efficiencies, affect competition. We believe that in the North region our extensive acreage position, existing natural gas gathering and pipeline systems in West Virginia, services and equipment that we have secured for the upcoming years and storage fields in West Virginia enhance our competitive position over other producers who do not have similar systems or services in place. We also actively compete against other companies with substantially larger financial and other resources.

OTHER BUSINESS MATTERS

Major Customer

In 2010, one customer accounted for approximately 11%, of the Company’s total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively, of the Company’s total sales. In 2008, one customer accounted for approximately 16% of the Company’s total sales.

Seasonality

Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the colder winter months.

Regulation of Oil and Natural Gas Exploration and Production

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.

Natural Gas Marketing, Gathering and Transportation

Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (NGA), the FERC regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC has granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of gas for resale without further FERC approvals. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the

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provisions of the Energy Policy Act of 2005 (2005 Act), the NGA has been amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established new regulations that are intended to increase natural gas pricing transparency through, among other things, requiring market participants to report their gas sales transactions annually to the FERC, and new regulations that require certain non-interstate pipelines to post daily scheduled volume information and design capacity for certain points on their systems. The 2005 Act also significantly increased the penalties for violations of the NGA and the FERC’s regulations. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties in an effort to add greater fairness, consistency and transparency to its enforcement program.

Our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation, because the prices we receive for our production are affected by the cost of transporting the gas to the consuming market. Through a series of comprehensive rulemakings, beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters, and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other, and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

In light of these statutory and regulatory changes, most pipelines have divested their gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants, and most pipelines have also implemented the large-scale divestiture of their gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines thus now generally provide unbundled, open and nondiscriminatory transportation and transportation-related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. Sellers and buyers of gas have gained direct access to the particular pipeline services they need, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace.

Certain of our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation (DOT) and the West Virginia Public Service Commission. In 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (2002 Act), which contains a number of provisions intended to increase pipeline operating safety. The DOT’s final regulations implementing the act became effective February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission and non-rural gathering pipeline facilities within the next ten years, and at least every seven years thereafter. On March 15, 2006, the DOT revised these regulations to define more clearly the categories of gathering facilities subject to DOT regulation, establish new safety rules for certain gathering lines in rural areas, revise the current regulations applicable to safety and inspection of gathering lines in non-rural areas, and adopt new compliance deadlines. The initial baseline assessments for our pipeline system in West Virginia are 95% completed. Clarification from the DOT published in 2009 brought to light the need for further baseline assessments of cased pipeline crossings covered under our integrity management program. With this exception, reassessment of our West Virginia pipeline system is scheduled to start in 2013 based on the 7 year reassessment requirement. We have completed 100% of the required initial inspection (baseline assessment) under our integrity management program of our pipeline systems in West Virginia. In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which reauthorized the programs adopted under the 2002 Act, proposed enhancements for state programs to reduce excavation damage to pipelines, established increased federal enforcement of one-call excavation programs, and established a new program for review of pipeline security plans and critical facility inspections.

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On December 3, 2009, the DOT adopted a regulation requiring gas and hazardous liquid pipelines that use supervisory control and data acquisition (SCADA) systems and have at least one controller and control room to develop written control room management procedures by August 1, 2011 and implement the procedures by February 1, 2013. In a Proposed Rulemaking issued September 17, 2010, the DOT proposed to expedite the program implementation deadline to August 1, 2011 for most of the requirements, except for certain provisions regarding adequate information and alarm management, which would have a program implementation deadline of August 1, 2012. On November 26, 2010, the DOT updated its reporting requirements for natural gas and hazardous liquid pipelines to be effective January 1, 2011.

We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, it is impossible to predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the recent trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, cannot be predicted.

Federal Regulation of Petroleum

Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2010, to implement this required five-year re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 2.65 percent should be the oil pricing index for the five-year period beginning July 1, 2011. Another FERC matter that may impact our transportation costs relates to a policy that allows a pipeline structured as a master limited partnership or similar non-corporate entity to include in its rates a tax allowance with respect to income for which there is an “actual or potential income tax liability,” to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest is required to file a tax return that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. We currently do not transport any of our oil or natural gas liquids on a pipeline structured as a master limited partnership.

We are not able to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or of the application of the FERC’s policy on income tax allowances.

Environmental Regulations

General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating, and can affect the timing of installing and operating, oil and gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us.

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The transition zone and shallow-water areas of the U.S. Gulf Coast are ecologically sensitive. Environmental issues have led to higher drilling costs and a more difficult and lengthy well permitting process. U.S. laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment.

Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination.

We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.

Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner and operator of a site and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.

Oil Pollution Act. The Federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. We believe that we substantially comply with the Oil Pollution Act and related federal regulations.

Clean Water Act. The Federal Water Pollution Control Act (Clean Water Act) and resulting regulations, which are primarily implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewaters to facilities owned by others that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations.

Clean Air Act. Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally

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resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.

Hydraulic Fracturing. Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs. However, bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including but not limited to requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, both the State of Pennsylvania and certain local governments in that state have adopted a variety of regulations limiting how and where fracturing can be performed. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

Greenhouse Gas. In response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth’s atmosphere, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases from sources within the United States between 2012 and 2050. For example, the 110th session of Congress considered various bills that proposed a “cap and trade” scheme of regulation of greenhouse gas emissions that generally would ban emissions above a defined reducing annual cap. Covered parties would be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs require either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved.

Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of oil or natural gas we produce. Although we would not be impacted to a greater degree than other similarly situated producers of oil and gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and gas we produce.

Also, in the wake of the U.S. Supreme Court’s decision in April 2007 in Massachusetts v. Environmental Protection Agency, the EPA has begun to regulate carbon dioxide and other greenhouse gas emissions, even though Congress has yet to adopt new legislation specifically addressing emissions of greenhouse gases. In late 2009, the EPA issued a “Mandatory Reporting of Greenhouse Gases” final rule, which was amended in

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December 2010, establishing a new comprehensive regulation and reporting scheme for operators of stationary sources emitting certain levels of greenhouse gases, and a Final Rule finding that certain current and projected levels of greenhouse gases in the atmosphere threaten public health and welfare of current and future generations. Most recently, in late 2010, the EPA finalized new greenhouse gas reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA’s greenhouse gas reporting rule. Please read “Item 1A. Risk Factors—Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for oil and gas.”

Employees

As of December 31, 2010, we had 409 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement.

Website Access to Company Reports

We make available free of charge through our website, www.cabotog.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on our website is not a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by the Company. The public may read and copy materials that we file with the SEC at the SEC’s Public Reference Room located at 100 F Street, NE, Washington, DC 20549. Information regarding the operation of the Public Reference Room can be obtained by calling the SEC at 1-800-SEC-0330.

Corporate Governance Matters

The Company’s Corporate Governance Guidelines, Corporate Bylaws, Code of Business Conduct, Corporate Governance and Nominations Committee Charter, Compensation Committee Charter and Audit Committee Charter are available on the Company’s website at www.cabotog.com, under the “Governance” section of “Investor Info.” Requests can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas, 77024.

ITEM 1A. RISK FACTORS

Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Natural gas prices have increased from an average price of $3.99 per Mmbtu in 2009 to an average price of $4.39 per Mmbtu in 2010. Oil prices have increased from an average price of $61.80 per barrel in 2009 to an average price of $77.32 per barrel in 2010. Depressed prices in the future would have a negative impact on our future financial results. Because our reserves are predominantly natural gas, changes in natural gas prices have a particularly large impact on our financial results.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

• the level of consumer product demand;

• weather conditions;

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• political conditions in natural gas and oil producing regions, including the Middle East;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• the price of foreign imports;

• actions of governmental authorities;

• pipeline availability and capacity constraints;

• inventory storage levels;

• domestic and foreign governmental regulations;

• the price, availability and acceptance of alternative fuels; and

• overall economic conditions.

These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. If natural gas prices decline significantly for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.

Drilling natural gas and oil wells is a high-risk activity.

Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors beyond our control, including:

• unexpected drilling conditions, pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions;

• compliance with governmental requirements; and

• shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.

Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate for activity within a particular geographic area may decline. We may ultimately not be able to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may not be able to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:

• the results of exploration efforts and the acquisition, review and analysis of the seismic data;

• the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

• the approval of the prospects by other participants after additional data has been compiled;

• economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;

• our financial resources and results; and

• the availability of leases and permits on reasonable terms for the prospects.

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These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.

Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated.

Reserve engineering is a subjective process of estimating underground accumulations of natural gas and crude oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas and oil prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds.

Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and crude oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.

You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board (FASB) in Accounting Standards Codification 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.

In general, the production rate of natural gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas and oil production and lower revenues and cash flow from operations. Our future natural gas and oil production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low natural gas and oil prices may further limit the kinds of reserves that we can develop economically. Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

Our reserve report estimates that production from our proved developed producing reserves as of December 31, 2010 will increase at an estimated rate of 30% during 2011 and then decline at estimated rates of 22%, 22% and 15% during 2012, 2013 and 2014, respectively. Future development of proved undeveloped and other reserves currently not classified as proved developed producing will impact these rates of decline. Because of higher initial decline rates from newly developed reserves, we consider this pattern fairly typical.

Exploration, development and exploitation activities involve numerous risks that may result in dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves.

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Acquired properties may not be worth what we pay due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include exploration potential, future natural gas and oil prices, operating costs, and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. Often, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. If an acquired property is not performing as originally estimated, we may have an impairment which could have a material adverse effect on our financial position and results of operations.

The integration of the properties we acquire could be difficult, and may divert management’s attention away from our existing operations.

The integration of the properties we acquire could be difficult, and may divert management’s attention and financial resources away from our existing operations. These difficulties include:

• the challenge of integrating the acquired properties while carrying on the ongoing operations of our business; and

• the possibility of faulty assumptions underlying our expectations.

The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing business. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

We face a variety of hazards and risks that could cause substantial financial losses.

Our business involves a variety of operating risks, including:

• well site blowouts, cratering and explosions;

• equipment failures;

• uncontrolled flows of natural gas, oil or well fluids;

• fires;

• formations with abnormal pressures;

• pollution and other environmental risks; and

• natural disasters.

Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, impairment of our operations and substantial losses to us.

Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these

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risks. As of December 31, 2010, we owned or operated approximately 3,150 miles of natural gas gathering and pipeline systems. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe periodically require repair, replacement or additional maintenance.

Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays.

Bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, both the State of Pennsylvania and certain local governments in that state have adopted a variety of regulations limiting how and where fracturing can be performed. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

We may not be insured against all of the operating risks to which we are exposed.

We maintain insurance against some, but not all, of these risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

We have limited control over the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest. Non-operated wells represented approximately 14.9% of our total owned gross wells, or approximately 4.6% of our owned net wells, as of December 31, 2010. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

Terrorist activities and the potential for military and other actions could adversely affect our business.

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.

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Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.

The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain these services on acceptable terms could materially harm our business.

Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.

Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry.

We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas and oil.

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 2010 we employed natural gas and crude oil price swap agreements for portions of our 2010 production and natural gas price swap agreements and crude oil collar agreements for portions of our anticipated 2011 production to attempt to manage price risk more effectively. In addition, we have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting.

The collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place. These hedging arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

• a counterparty is unable to satisfy its obligations;

• production is less than expected; or

• there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our use of derivatives.

The loss of key personnel could adversely affect our ability to operate.

Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or

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more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.

Our operations are subject to extensive federal, state and local laws and regulations, including tax laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and gas that we produce.

There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases. In the United States, climate change action is evolving at state, regional and federal levels. On December 17, 2010, the EPA amended the “Mandatory Reporting of Greenhouse Gases” final rule (“Reporting Rule”) originally issued in September 2009. The Reporting Rule establishes a new comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent greenhouse gases to inventory and report their greenhouse gases emissions annually on a facility-by-facility basis. In addition, on December 15, 2009, the EPA published a Final Rule finding that current and projected concentrations of six key greenhouse gases in the atmosphere threaten public health and the welfare of current and future generations. The EPA also found that the combined emissions of these greenhouse gases from new motor vehicles and new motor vehicle engines contribute to pollution that threatens public health and welfare. This Final Rule, also known as the EPA’s Endangerment Finding, does not impose any requirements on industry or other entities directly. However, following issuance of the Endangerment Finding, EPA promulgated final motor vehicle GHG emission standards on April 1, 2010, the effect of which could reduce demand for motor fuels refined from crude oil. Also, according to the EPA, the final motor vehicle GHG standards will trigger construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, EPA issued a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi step process, with the largest sources first subject to permitting. Most recently, on November 8, 2010, EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA’s GHG Reporting Rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year will now be required to report annual GHG emissions to EPA, with the first report due on March 31, 2012.

However, following issuance of the Endangerment Finding, the EPA promulgated final motor vehicle greenhouse gas emission standards on April 1, 2010, the effect of which could reduce demand for motor fuels refined from crude oil. Also, according to the EPA, the final motor vehicle greenhouse gas standards will trigger

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construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, the EPA issued a final rule to address permitting of greenhouse gas emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule tailors the PSD and Title V programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. Most recently, on November 8, 2010, the EPA finalized new greenhouse gas reporting requirements for upstream petroleum and natural gas systems, which will be added to the Reporting Rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of C02 equivalent per year will now be required to report annual GHG emissions to the EPA, with the first report due on March 31, 2012.

Internationally, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. While it is not possible at this time to predict how regulation that may be enacted to address greenhouse gases emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States in which we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy sources) could have a negative impact on our business if such incentives reduce demand for oil and gas.

Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. To the extent that such unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make estimating any future financial risk to our operations caused by these potential physical risks of climate change extremely challenging.

The proposed U.S. federal budget for fiscal year 2012 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

On February 14, 2011, the Office Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2012, and the Treasury Department released a general explanation of tax related proposals in such budget. The proposed budget repeals many tax incentives and deductions that are currently used by U.S. oil and gas companies and imposes new taxes. The provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; increase in the taxation of foreign source income; repeal of the manufacturing tax deduction for oil and gas companies; and increase in the geological and geophysical amortization period for independent producers. Should some or all of these provisions become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities in the U.S. Since none of these proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business.

Provisions of Delaware law and our bylaws and charter could discourage change in control transactions and prevent stockholders from receiving a premium on their investment.

Our bylaws provide for a classified Board of Directors with staggered terms, and our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit stockholder action by written consent and limit stockholder proposals at meetings of stockholders. Because of these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals

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may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.

The personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our charter.

The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors’ duty of care to equitable remedies such as injunction or rescission. Our charter limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:

• for any breach of their duty of loyalty to the company or our stockholders;

• for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

• under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and

• for any transaction from which the director derived an improper personal benefit.

This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See Item 1. “Business.”

ITEM 3. LEGAL PROCEEDINGS

The Company is a defendant in various legal proceedings arising in the normal course of business. When deemed necessary, the Company establishes reserves for certain legal proceedings. All known liabilities are accrued based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Environmental Matters

On November 4, 2009, the Company and the Pennsylvania Department of Environmental Protection (PaDEP) entered into a single settlement agreement (Consent Order) covering a number of separate, unrelated environmental issues occurring in 2008 and 2009, including releases of drilling mud and other substances, record keeping violations at various wells and alleged natural gas contamination of 13 water wells in Susquehanna County, Pennsylvania. The Company paid an aggregate $120,000 civil penalty with respect to all the matters covered by the Consent Order, which were consolidated at the request of the PaDEP.

On April 15, 2010, the Company and PaDEP reached agreement on modifications to the Consent Order (First Modified Consent Order). In the First Modified Consent Order, PaDEP and the Company agreed that the

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Company will provide a permanent source of potable water to 14 households, most of which the Company has already been supplying with water. The Company agreed to plug and abandon three vertical wells in close proximity to two of the households and to bring into compliance a fourth well in the nine square mile area of concern in Susquehanna County. The Company agreed to complete these actions prior to any new well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of concern. The Company also agreed to postpone drilling of new wells in the area of concern until all obligations under the consent orders are fulfilled. In addition, the Company agreed to take certain other actions if requested by PaDEP, which could include the plugging and abandonment of up to 10 additional wells. Under the First Modified Consent Order, the Company paid a $240,000 civil penalty and agreed to pay an additional $30,000 per month until all obligations under the First Modified Consent Order are satisfied.

On July 19, 2010, the Company and the PaDEP entered a Second Modification to Consent Order (Second Modified Consent Order) under which the Company and the PaDEP agreed that the Company has satisfactorily plugged and abandoned the three vertical wells and brought the fourth well into compliance. As a result, the Company and the PaDEP agreed that the PaDEP will commence the processing and issuance of new well drilling permits outside the area of concern so long as the Company continues to provide temporary potable water and offers to provide gas/water separators to the 14 households. No penalties were assessed under the Second Modified Consent Order.

As required by the Second Modified Consent Order, the Company made offers to provide whole-house water treatment systems to the 14 households. As required by the First Modified Consent Order, on August 5, 2010 the Company filed with the PaDEP its report, prepared by its experts, finding that the Company’s well drilling and development activities are not the source of methane gas reported to be in the groundwater and water wells in the area of concern.

Despite the Company’s vigorous efforts to comply with the various consent orders, in a September 14, 2010 letter to the Company, the PaDEP rejected the Company’s expert report and determined that the Company’s drilling activities continue to cause the unpermitted discharge of natural gas into the groundwater and continue to affect residential water supplies in the area of concern. The PaDEP directed the Company, in accordance with the First Modified Consent Order, to plug or take other remedial actions at the remaining 10 wells and to contact the PaDEP to discuss connecting the impacted water supplies into a community public water system to permanently eliminate the continuing adverse affect to those water supplies.

The Company believed that it was in full compliance with the various consent orders. In a September 28, 2010 reply letter to the PaDEP, the Company disagreed with the PaDEP’s rejection of the Company’s expert report, disagreed that the remaining 10 wells continue to impact groundwater and affect residential water supplies and disagreed that a community public water system is necessary or feasible. It was the Company’s position that offering installation of a whole-house water treatment system to the 14 households constituted compliance with the Company’s obligations under these consent orders.

On December 15, 2010, the Company entered a global settlement agreement and new consent order with the PaDEP (Global Settlement Agreement), which supersedes the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. Under the Global Settlement Agreement, among other things, the Company agreed to pay $4.2 million into separate escrow accounts for the benefit of each affected household, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, remediate two wells in the affected area, provide pressure, water quality and well headspace data to the PaDEP and offer water treatment to the affected households. The Global Settlement Agreement settles all outstanding issues and claims that are known and that could have been brought against the Company by the PaDEP relating to the wells in the affected area and the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. It also allows the Company to begin hydraulic fracturing in the affected areas after providing the PaDEP with well pressure data and to commence drilling new wells in the affected area in the second quarter of 2011. Under the Global Settlement Agreement, the Company has no obligation to connect the impacted water supplies to a community public water system.

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On January 11, 2011, certain of the affected households appealed the Global Settlement Agreement to the Pennsylvania Environmental Hearing Board. A hearing on the merits of this appeal is not expected to occur until 2012.

As of December 31, 2010, the Company has paid $1.3 million in fines and penalties to the PaDEP, paid $0.6 million to two of the affected households and accrued a $3.6 million settlement liability related to this matter which is included in Other Liabilities in the Consolidated Balance Sheet.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information as of February 18, 2011 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.

Name	Age		Position	Officer Since
Dan O. Dinges		57	Chairman, President and Chief Executive Officer		2001
Scott C. Schroeder		48	Vice President and Chief Financial Officer and Treasurer		1997
G. Kevin Cunningham		57	Vice President, General Counsel		2010
Robert G. Drake		63	Vice President, Information Services and Operational Accounting		1998
Abraham D. Garza		64	Vice President, Human Resources		1998
Jeffrey W. Hutton		55	Vice President, Marketing		1995
Steven W. Lindeman		50	Vice President, Engineering and Technology		2011
Lisa A. Machesney		55	Vice President, Managing Counsel and Corporate Secretary		1995
James M. Reid		59	Vice President, Regional Manager South Region		2009
Todd M. Roemer		40	Controller		2010
Phillip L. Stalnaker		51	Vice President, Regional Manager North Region		2009

All officers are elected annually by our Board of Directors. All of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years, except for Mr. G. Kevin Cunningham and Mr. Todd M. Roemer.

Mr. Cunningham joined the Company in November 2009 as Associate General Counsel and was appointed as General Counsel in September 2010 and promoted to Vice President in 2011. Before joining the Company, Kevin was Regional Counsel-Southern Division at Chesapeake Energy from 2006 until November 2009. He is a graduate of the University of Texas School of Law and has worked at Fortune 500 E&P companies in both legal and business positions since 1982.

Mr. Lindeman was promoted to Vice President, Engineering and Technology, in February 2011. He began his career as a Drilling Engineer in Meadville, Pennsylvania with Cabot in 1982, has served in various management positions in many company offices over the years, including Pampa and Midland, Texas, Indiana, Meadville, and Pittsburgh, Pennsylvania, before moving to Houston in 1992, where he most recently served as Director of Engineering. Mr. Lindeman is a graduate of the University of Pittsburgh; he holds a Bachelor of Science degree in Chemical Engineering specializing in Petroleum Engineering. He has been a member of the Society of Petroleum Engineers since 1980.

Mr. Roemer joined the Company in February 2010 after a 14 year career in PricewaterhouseCoopers’ energy practice. He is a graduate of the University of Houston—Clear Lake with a Bachelor of Science degree in Accounting. Mr. Roemer is a Certified Public Accountant.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed and principally traded on the New York Stock Exchange under the ticker symbol “COG.” The following table presents the high and low closing sales prices per share of our common stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the common stock are also shown. A regular dividend has been declared each quarter since we became a public company in 1990.

	High		Low		Dividends
2010
First Quarter	$	46.23	$	36.40	$	0.03
Second Quarter	$	40.51	$	30.33	$	0.03
Third Quarter	$	33.61	$	26.99	$	0.03
Fourth Quarter	$	37.85	$	28.27	$	0.03
2009
First Quarter	$	30.76	$	18.14	$	0.03
Second Quarter	$	36.90	$	24.38	$	0.03
Third Quarter	$	39.23	$	27.98	$	0.03
Fourth Quarter	$	45.73	$	34.14	$	0.03

As of February 1, 2011, there were 496 registered holders of the common stock.

ISSUER PURCHASES OF EQUITY SECURITIES

Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During 2010, we did not repurchase any shares of common stock. All purchases executed to date have been through open market transactions. The maximum number of remaining shares that may be purchased under the plan as of December 31, 2010 was 4,795,300.

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PERFORMANCE GRAPH

The following graph compares our common stock performance (“COG”) with the performance of the Standard & Poors’ 500 Stock Index and the Dow Jones US Exploration & Production Index for the period December 2005 through December 2010. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2005 and that all dividends were reinvested.

CALCULATED VALUES	2005		2006		2007		2008		2009		2010
S&P 500		100.0		115.8		122.2		77.0		97.3		112.0
COG		100.0		134.9		180.1		116.4		195.8		170.6
Dow Jones US Exploration & Production		100.0		105.4		151.4		90.6		127.4		148.7

* Year-end closing values.

The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.

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ITEM 6. SELECTED FINANCIAL DATA

The following table summarizes our selected consolidated financial data for the periods indicated. This information should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7, and the Consolidated Financial Statements and related Notes in Item 8.

	Year Ended December 31,
(In thousands, except per share amounts)	2010		2009			2008		2007		2006
Statement of Operations Data
Operating Revenues	$	884,035	$	879,276		$	945,791	$	732,170	$	761,988
Impairment of Oil & Gas Properties and Other Assets(1)		40,903		17,622			35,700		4,614		3,886
Gain / (Loss) on Sale of Assets(2)		106,294		(3,303	)		1,143		13,448		232,017
Gain on Settlement of Dispute(3)		—		—			51,906		—		—
Income from Operations		266,439		282,269			372,012		274,693		528,946
Net Income		103,386		148,343			211,290		167,423		321,175
Basic Earnings per Share(4)	$	0.99	$	1.43		$	2.10	$	1.73	$	3.32
Diluted Earnings per Share(4)	$	0.98	$	1.42		$	2.08	$	1.71	$	3.26
Dividends per Common Share(4)	$	0.12	$	0.12		$	0.12	$	0.11	$	0.08
Balance Sheet Data
Properties and Equipment, Net.	$	3,762,760	$	3,358,199		$	3,135,828	$	1,908,117	$	1,480,201
Total Assets		4,005,031		3,683,401			3,701,664		2,208,594		1,834,491
Current Portion of Long-Term Debt		—		—			35,857		20,000		20,000
Long-Term Debt		975,000		805,000			831,143		330,000		220,000
Stockholders’ Equity		1,872,700		1,812,514			1,790,562		1,070,257		945,198

⁽¹⁾ For discussion of impairment of oil and gas properties and other assets, refer to Note 2 of the Notes to the Consolidated Financial Statements.

⁽²⁾ Gain on Sale of Assets in 2010 includes $40.7 million from the sale of the Company’s investment in Tourmaline, $49.3 million from the sale of our Pennsylvania gathering infrastructure, $10.8 million from the sale of certain oil and gas properties in the Texas Panhandle, a $10.3 million gain on the sale of our Woodford shale properties, and an impairment loss of $5.8 million on certain oil and gas properties in Colorado. Gain on Sale of Assets for 2007 and 2006 reflects $12.3 million and $231.2 million, respectively, related to disposition of our offshore portfolio and certain south Louisiana properties, which was substantially completed in the third quarter of 2006.

⁽³⁾ Gain on Settlement of Dispute is associated with the Company’s settlement of a dispute in the fourth quarter of 2008. The dispute settlement includes the value of cash and properties received. See Note 8 of the Notes to the Consolidated Financial Statements.

⁽⁴⁾ All Earnings per Share and Dividends per Common Share figures have been retroactively adjusted for the 2-for-1 split of our common stock effective March 31, 2007.

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 results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.

In 2009, we reorganized our operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with our Texas and Louisiana areas to form the South region. Additionally, we exited Canada through the sale of our properties in April 2009. Prior to the third quarter of 2009, we presented our geographic areas as East, Gulf Coast, West and Canada. Certain prior year amounts have been reclassified to reflect changes in presenting the geographic areas in which we conduct our operations.

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We operate in one segment, natural gas and oil development, exploitation and exploration, exclusively within the United States.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read “Forward-Looking Information” for further details.

OVERVIEW

Cabot Oil & Gas Corporation is a leading independent oil and gas company engaged in the development, exploitation, exploration, production and marketing of natural gas, crude oil and, to a lesser extent, natural gas liquids from its properties in the Continental United States. We also transport, store, gather and produce natural gas for resale. Our exploitation and exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. Our program is designed to be disciplined and balanced, with a focus on achieving strong financial returns.

We evaluate three types of investment alternatives that compete for available capital: drilling opportunities, financial opportunities such as debt repayment or repurchase of common stock and acquisition opportunities. Depending on circumstances, we allocate capital among the alternatives based on a rate-of-return approach. Our goal is to invest capital in the highest return opportunities available at any given time. At any one time, one or more of these may not be economically feasible.

Our financial results depend upon many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Price volatility in the commodity markets has remained prevalent in the last few years. Our realized natural gas and crude oil price was $5.54 per Mcf and $97.91 per Bbl, respectively, in 2010 and were significantly increased by our positions from our derivative instruments, which contributed approximately 22% of our realized revenues in 2010. In an effort to manage commodity price risk, we opportunistically enter into crude oil and natural gas price swaps and collars. These financial instruments are a component of our risk management strategy.

Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. See “Risk Factors—Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business” and “Risk Factors—Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable” in Item 1A.

The table below illustrates how natural gas prices have fluctuated by month over 2009 and 2010. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2009” and “2010” price is the natural gas price per Mcf realized by us and includes the realized impact of our natural gas derivative instruments, as applicable:

	Natural Gas Prices by Month - 2010
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	5.82	$	5.28	$	4.81	$	3.84	$	4.27	$	4.16	$	4.73	$	4.78	$	3.64	$	3.84	$	3.29	$	4.27
2010	$	6.95	$	6.47	$	6.28	$	5.35	$	5.49	$	5.60	$	5.66	$	5.64	$	4.84	$	4.99	$	4.66	$	5.39
	Natural Gas Prices by Month - 2009
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	6.16	$	4.49	$	4.07	$	3.65	$	3.33	$	3.54	$	3.96	$	3.37	$	2.84	$	3.72	$	4.28	$	4.49
2009	$	7.72	$	7.32	$	7.46	$	7.03	$	7.28	$	7.45	$	7.50	$	7.45	$	7.25	$	7.42	$	8.03	$	7.75

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The table below illustrates how crude oil prices have fluctuated by month over 2009 and 2010. “Index” represents the NYMEX monthly average crude oil price and our realized per barrel (Bbl) crude oil prices by month for 2009 and 2010. The “2009” and “2010” price is the crude oil price per Bbl realized by us and includes the realized impact of our crude oil derivative instruments:

	Crude Oil Prices by Month - 2010
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	72.47	$	77.62	$	80.16	$	81.25	$	83.45	$	68.01	$	77.21	$	77.44	$	73.46	$	73.52	$	81.77	$	81.51
2010	$	101.75	$	96.32	$	95.25	$	97.07	$	94.48	$	98.82	$	99.00	$	101.47	$	94.95	$	101.01	$	97.51	$	100.24
	Crude Oil Prices by Month - 2009
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	41.92	$	39.26	$	48.06	$	49.95	$	59.21	$	69.70	$	64.29	$	71.14	$	69.47	$	75.82	$	78.15	$	74.60
2009	$	75.41	$	73.98	$	76.29	$	78.86	$	85.94	$	86.26	$	82.22	$	92.16	$	87.54	$	92.13	$	95.35	$	95.41

Natural gas revenues decreased from 2009 to 2010 as a result of decreased commodity market prices partially offset by increased natural gas production. Crude oil revenues increased slightly from 2009 to 2010 primarily due to increased realized prices, partially offset by decreased crude oil production. Prices, including the realized impact of derivative instruments, decreased by 26% for natural gas and increased by 14% for oil.

We drilled 113 gross wells with a success rate of 98% in 2010 compared to 143 gross wells with a success rate of 95% in 2009. Total capital and exploration expenditures increased by $251.1 million to $891.5 million in 2010 compared to $640.4 million in 2009. This increase was due to a $230.6 million increase in the North region substantially driven by an expanded Marcellus horizontal drilling program in northeast Pennsylvania to hold acreage and $42.8 million in the South region due to due to an increase in lease acquisitions to establish a greater position in the oil window of the Eagle Ford shale. We believe our cash on hand and operating cash flow in 2011 will be sufficient to fund our budgeted capital and exploration spending of approximately $600 million. Any additional needs are expected to be funded by borrowings from our credit facility.

Our 2011 strategy will remain consistent with 2010. We will remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure sufficient liquidity, including cash resources and available credit. In the current year we have allocated our planned program for capital and exploration expenditures primarily to the Marcellus shale in northeast Pennsylvania, and the Eagle Ford shale in south Texas. We believe these strategies are appropriate for our portfolio of projects and the current industry environment and will continue to add shareholder value over the long-term.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.

FINANCIAL CONDITION

Capital Resources and Liquidity

Our primary sources of cash in 2010 were from funds generated from the sale of natural gas and crude oil production (including hedge realizations), borrowings under our revolving credit facility, issuance of private placement debt and the sales of properties and other assets during the year. These cash flows were primarily used to fund our development and exploratory expenditures, in addition to repayments for debt and related interest, payments for debt issuance costs, contributions to our pension plan and dividends. See below for additional discussion and analysis of cash flow.

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We generate cash from the sale of natural gas and crude oil. Operating cash flow fluctuations are substantially driven by commodity prices and changes in our production volumes. Prices for crude oil and natural gas have historically been volatile, including seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have also influenced prices throughout the recent years. In addition, fluctuations in cash flow may result in an increase or decrease in our capital and exploration expenditures. See “Results of Operations” for a review of the impact of prices and volumes on revenues.

Our working capital is also substantially influenced by variables discussed above. From time to time, our working capital will reflect a surplus, while at other times it will reflect a deficit. This fluctuation is not unusual. We believe we have adequate availability under our credit facility and liquidity available to meet our working capital requirements.

	Year Ended December 31,
(In thousands)	2010			2009			2008
Cash Flows Provided by Operating Activities	$	484,911		$	614,052		$	634,447
Cash Flows Used in Investing Activities		(613,741	)		(531,027	)		(1,452,289	)
Cash Flows Provided by / (Used in) Financing Activities		144,621			(70,968	)		827,445
Net Increase / (Decrease) in Cash and Cash Equivalents	$	15,791		$	12,057		$	9,603

Operating Activities. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities in 2010 decreased by $129.1 million over 2009. This decrease was mainly due to a decrease in oil and gas revenues and higher operating and interest expense. Average realized natural gas prices decreased by 26% in 2010 compared to 2009 and average realized crude oil prices increased by 14% over the same period. Equivalent production volumes increased by 27% in 2010 compared to 2009 primarily due to higher natural gas production. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities. Realized prices may continue to decline during 2011.

For 2010, we had natural gas price swaps covering 35.9 Bcf, or 29%, of our 2010 natural gas production at an average price of $9.30 per Mcf. We also had crude oil price swaps covering 730 Mmbl, or 90%, of our 2010 crude oil production at an average price of $104.25 per Bbl. As of December 31, 2010, we have natural gas price swaps covering 12.9 Bcf of our 2011 gas production at an average price of $6.24 per Mcf and crude oil collars covering 365 MBbls of our 2011 crude oil production, with a floor of $80.00 per Bbl and a ceiling of $93.25 per Bbl. Accordingly, based on our current hedge position, we will be more subject to the effects of natural gas and crude oil price volatility in 2011 than in 2010. In addition, given the current market for derivatives, if we were to hedge all our 2011 production, we would expect our realized prices to be lower than our 2010 realized prices.

Net cash provided by operating activities in 2009 decreased by $20.4 million over 2008. This decrease was mainly due to a decrease in oil and gas revenues, partially offset by lower operating, interest and tax expense. Average realized natural gas prices decreased by 11% in 2009 compared to 2008 and average realized crude oil prices decreased by 4% over the same period. Equivalent production volumes increased by 8% in 2009 compared to 2008 as a result of higher natural gas and crude oil production.

See “Results of Operations” for a discussion on commodity prices and a review of the impact of prices and volumes on sales revenue.

Investing Activities. The primary uses of cash in investing activities were capital spending and exploration expenses. We established the budget for these amounts based on our current estimate of future commodity prices and cash flows. Due to the volatility of commodity prices and new opportunities which may arise, our capital

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expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased by $82.7 million from 2009 to 2010 and decreased by $921.3 million from 2008 to 2009. The increase from 2009 to 2010 was due to an increase of $246.4 million in acquisitions and capital and exploration expenditures partially offset by an increase of $163.3 million of proceeds from the sale of assets.

The decrease from 2008 to 2009 was due to a decrease of $843.2 million in acquisitions and capital expenditures and an increase of $78.1 million of proceeds from the sale of assets. In August 2008, we completed the acquisition of producing properties, leasehold acreage and a natural gas gathering infrastructure in east Texas for total net cash consideration of approximately $604.0 million.

Financing Activities. Cash flows provided by financing activities increased by $215.6 million from 2009 to 2010. This was primarily due to an increase in borrowings of $420.0 million, partially offset by an increase in repayments of debt of $188.0 million, an increase in cash paid for capitalized debt issuance costs by a total of $3.4 million and a decrease of $13.7 million in the tax benefit associated with stock-based compensation.

Cash flows provided by financing activities decreased by $898.4 million from 2008 to 2009. This was primarily due to a decrease in borrowings from debt of $787 million, partially offset by a decrease in repayments of debt of $208 million, and a decrease in net proceeds from the sale of common stock of $316.1 million primarily due to our June 2008 issuance of common stock in a public offering. Common stock proceeds and debt borrowings in 2008 were largely used to finance the acquisition of east Texas properties and undeveloped acreage. Cash paid for capitalized debt issuance costs and dividends increased by a total of $6.4 million, partially offset by an increase of $3.1 million in the tax benefit associated with stock-based compensation.

At December 31, 2010, we had $213.0 million of borrowings outstanding under our unsecured credit facility at a weighted-average interest rate of 3.1%.

In December 2010, we completed a private placement of $175.0 million aggregate principal amount of senior unsecured fixed-rate notes with a weighted-average interest rate of 5.58%, consisting of amounts due in January 2021, 2023 and 2026.

In September 2010, we amended and restated our revolving credit facility to increase the available credit line to $900 million with an accordion feature allowing us to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount, and to extend the term to September 2015. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks based on our reserve reports and engineering reports) and certain other assets and the outstanding principal balance of our senior notes. The amended facility provides for a $1.5 billion borrowing base. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. As of December 31, 2010, our available credit under our credit facility is $525.0 million.

In June 2010, we amended the agreements governing our credit facility and senior notes to amend the required asset coverage ratio (the present value of our proved reserves plus working capital to debt) contained in the agreements. The amendment also changed the ratio for maximum calculated indebtedness to borrowing base (as defined in the credit facility agreement).

In July 2008, we completed a private placement of $425 million aggregate principal amount of senior unsecured fixed-rate notes with a weighted-average interest rate of 6.51%, consisting of amounts due in July 2018, 2020 and 2023. In December 2008, we completed a private placement of $67 million aggregate principal amount of senior unsecured 9.78% fixed-rate notes due in December 2018.

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In June 2008, we entered into an underwriting agreement pursuant to which we sold an aggregate of 5,002,500 shares of common stock at a price to us of $62.66 per share. We received $313.5 million in net proceeds, after deducting underwriting discounts and commissions. These net proceeds were used temporarily to reduce outstanding borrowings under our revolving credit facility prior to funding a portion of the purchase price of our east Texas acquisition, which closed in the third quarter of 2008. Immediately prior to (and in connection with) this issuance, we retired 5,002,500 shares of treasury stock, which had a weighted-average purchase price of $16.46.

Management believes that, with internally generated cash, existing cash and availability under our revolving credit facility, we have the capacity to finance our spending plans and maintain our strong financial position. At the same time, we will closely monitor the capital markets.

Capitalization

Information about our capitalization is as follows:

	December 31,
(Dollars in thousands)	2010			2009
Debt(1)	$	975,000		$	805,000
Stockholders’ Equity	$	1,872,700		$	1,812,514
Total Capitalization	$	2,847,700		$	2,617,514
Debt to Capitalization		34	%		31	%
Cash and Cash Equivalents	$	55,949		$	40,158

⁽¹⁾ Includes $213.0 million and $143.0 million of borrowings outstanding under our revolving credit facility at December 31, 2010 and 2009, respectively.

For the year ended December 31, 2010, we paid dividends of $12.5 million ($0.12 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration activities, excluding any significant oil and gas property acquisitions, with cash generated from operations and, when necessary, borrowings under our revolving credit facility. We budget these capital expenditures based on our projected cash flows for the year.

The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 2010.

(In thousands)	2010		2009		2008
Capital Expenditures
Drilling and Facilities(1)	$	654,153	$	401,143	$	624,344
Leasehold Acquisitions		130,675		145,681		152,666
Acquisitions		801		394		624,975
Pipeline and Gathering		54,811		32,861		36,900
Other		8,368		9,506		10,855
		848,808		589,585		1,449,740
Exploration Expense		42,725		50,784		31,200
Total	$	891,533	$	640,369	$	1,480,940

⁽¹⁾ Includes Canadian currency translation effects of $4.6 million and $(27.7) million in 2009 and 2008, respectively. There was no impact from Canadian currency translation in 2010.

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We plan to drill approximately 110 gross wells (83.1 net) in 2011 compared with 113 gross wells (87.1 net) drilled in 2010. This 2011 drilling program includes approximately $600 million in total capital and exploration expenditures, down from $891.5 million in 2010. This decline is primarily due to the lower well count together with lower projected lease acquisition expenditures as the result of our reduced program spending due to lower commodity prices and reduced infrastructure investments. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease the capital and exploration expenditures accordingly.

There are many factors that impact our depreciation, depletion and amortization (DD&A) rate. These include reserve additions and revisions, development costs, impairments and changes in anticipated production in future periods. In 2011, management expects a small decrease in our DD&A rate primarily due to increased production and reserve additions in the Marcellus shale. Such changes in our DD&A rate and related expense do not have an impact on our cash flows.

Contractual Obligations

Our material contractual obligations include long-term debt, interest on long-term debt, firm gas transportation agreements, drilling rig commitments and operating leases. We have no off-balance sheet debt or other similar unrecorded obligations.

A summary of our contractual obligations as of December 31, 2010 are set forth in the following table:

			Payments Due by Year
(In thousands)	Total		2011		2012 to 2013		2014 to 2015		2016 & Beyond
Long-Term Debt(1)	$	975,000	$	—	$	75,000	$	—	$	900,000
Interest on Long-Term Debt(2)		448,894		59,140		112,780		99,098		177,876
Firm Gas Transportation Agreements(3)		485,619		32,504		64,040		56,712		332,363
Operating Leases(3)		22,158		5,414		9,902		6,842		—
Total Contractual Cash Obligations	$	1,931,671	$	97,058	$	261,722	$	162,652	$	1,410,239

⁽¹⁾ At December 31, 2010, we had $213.0 million of debt outstanding under our revolving credit facility. See Note 5 of the Notes to the Consolidated Financial Statements for details of long-term debt.

⁽²⁾ Interest payments have been calculated utilizing the fixed rates of our $762.0 million long-term debt outstanding at December 31, 2010. Interest payments on our revolving credit facility were calculated by assuming that the December 31, 2010 outstanding balance of $213.0 million will be outstanding through the September 2015 maturity date. A constant interest rate of 3.8% was assumed, which was the 2010 weighted-average interest rate. Actual results will differ from these estimates and assumptions.

⁽³⁾ For further information on our obligations under firm gas transportation agreements and operating leases, see Note 8 of the Notes to the Consolidated Financial Statements.

Amounts related to our asset retirement obligations are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at December 31, 2010 was $72.3 million, up from $29.7 million at December 31, 2009, primarily due to $40.4 million in revisions of previous estimates due to increased plugging and abandonment costs and $1.9 million in accretion expense during 2010. See Note 9 of the Notes to the Consolidated Financial Statements for further details.

Potential Impact of Our Critical Accounting Policies

Readers of this document and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. Our most significant policies are discussed below.

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Successful Efforts Method of Accounting

We follow the successful efforts method of accounting for our oil and gas producing activities. Acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole costs are expensed. Development costs, including costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.

Oil and Gas Reserves

The process of estimating quantities of proved reserves is inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as oil and gas prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in the interpretations or assumptions could materially affect the estimated quantity and value of our reserves.

Our reserves have been prepared by our petroleum engineering staff and audited by Miller & Lents, Ltd., independent petroleum engineers, who in their opinion determined the estimates presented to be reasonable in the aggregate. For more information regarding reserve estimation, including historical reserve revisions, refer to the “Supplemental Oil and Gas Information.”

Our rate of recording DD&A expense is dependent upon our estimate of proved and proved developed reserves, which are utilized in our unit-of-production method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. A five percent positive or negative revision to proved reserves throughout the Company would decrease or increase the DD&A rate by approximately ($0.10) to $0.12 per Mcfe. Revisions in significant fields may individually affect our DD&A rate. It is estimated that a positive or negative reserve revision of 10% in one of our most productive fields would have a ($0.06) to $0.07 per Mcfe impact on our total DD&A rate. These estimated impacts are based on current data, and actual events could require different adjustments to our DD&A rate.

In addition, a decline in proved reserve estimates may impact the outcome of our impairment test under Accounting Standards Codification (ASC) 360, “Property, Plant, and Equipment.” Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties and market sensitive commodity prices utilized in our impairment analysis, management cannot determine if an impairment is reasonably likely to occur in the future.

Carrying Value of Oil and Gas Properties

We evaluate the impairment of our oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices remain low or continue to decline, there could be a significant revision in the future. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil.

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Costs attributable to our unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past experience and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. Historically, the average property life in each of the regions has not significantly changed. The commodity price environment may impact the capital available for exploration projects as well as development drilling. We have considered these impacts when determining the amortization rate of our undeveloped acreage, especially in exploratory areas. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $17.3 million or decrease by approximately $12.3 million, respectively per year.

In the past, based on the customary terms of the leases, the average leasehold life in the South region has been shorter than the average life in the North region. Average property lives in the North and South regions have been five and three years, respectively. As these properties are developed and reserves are proven, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of our future exploration and development program.

Asset Retirement Obligation

The majority of our asset retirement obligation relates to the plugging and abandonment of oil and gas wells and to a lesser extent meter stations, pipelines, processing plants and compressors. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. The recognition of an asset retirement obligation requires management to make assumptions that include estimated plugging and abandonment costs, timing of settlements, inflation rates and discount rate. In periods subsequent to initial measurement, the asset retirement cost is allocated to expense using a systematic and rational method over the assets useful life, while increases in the discounted ARO liability resulting from the passage of time (accretion expense) is reflected as depreciation, depletion and amortization expense.

Accounting for Derivative Instruments and Hedging Activities

We follow the accounting prescribed in ASC 815. Under ASC 815, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Accumulated Other Comprehensive Income, a component of equity, to the extent that the derivative instrument is designated as a hedge and is effective. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of derivatives not qualifying as hedges, is recorded currently in earnings as a component of Natural Gas and Crude Oil and Condensate Revenue in the Consolidated Statement of Operations.

The fair value of our derivative instruments are measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The Company measured the nonperformance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions. In times where we have net derivative contract liabilities, our nonperformance risk is evaluated using a market credit spread provided by our bank.

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Employee Benefit Plans

Our costs of long-term employee benefits, particularly pension and postretirement benefits, are incurred over long periods of time, and involve many uncertainties over those periods. The net periodic benefit cost attributable to current periods is based on several assumptions about such future uncertainties, and is sensitive to changes in those assumptions. It is management’s responsibility, often with the assistance of independent experts, to select assumptions that in its judgment represent best estimates of those uncertainties. It also is management’s responsibility to review those assumptions periodically to reflect changes in economic or other factors that affect those assumptions. Significant assumptions used to determine our projected pension obligation and related costs include discount rates, expected return on plan assets, and rate of compensation increases, while the assumptions used to determine our postretirement benefit obligation and related costs include discount rates and health care cost trends. See Note 6 of the Notes to the Consolidated Financial Statements for a full discussion of our employee benefit plans.

Stock-Based Compensation

We account for stock-based compensation under a fair value based method of accounting prescribed under ASC 718. Under the fair value method, compensation cost is measured at the grant date and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is usually the vesting period. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. The use of these models requires significant judgment with respect to expected life, volatility and other factors. Stock-based compensation cost for all types of awards is included in General and Administrative Expense in the Consolidated Statement of Operations. See Note 12 of the Notes to the Consolidated Financial Statements for a full discussion of our stock-based compensation.

OTHER ISSUES AND CONTINGENCIES

Regulations. Our operations are subject to various types of regulation by federal, state and local authorities. See “Regulation of Oil and Natural Gas Exploration and Production,” “Natural Gas Marketing, Gathering and Transportation,” “Federal Regulation of Petroleum” and “Environmental Regulations” in the “Other Business Matters” section of Item 1 for a discussion of these regulations.

Restrictive Covenants. Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in our various debt instruments. Among other requirements, our revolving credit agreement and our senior notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. In addition, we are required to maintain an asset coverage ratio of the present value of proved reserves plus working capital to debt of 1.75 to 1.0 and a current ratio of 1.0 to 1.0. Our senior notes require us to maintain a ratio of cash and proved reserves to indebtedness and other liabilities of 1.75 to 1.0. At December 31, 2010, we were in compliance in all material respects with all restrictive covenants on both the revolving credit agreement and notes. In the unforeseen event that we fail to comply with these covenants, we may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation.

Operating Risks and Insurance Coverage. Our business involves a variety of operating risks. See “Risk Factors—We face a variety of hazards and risks that could cause substantial financial losses” in Item 1A. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs of these insurance policies are somewhat dependent on our historical claims experience and also the areas in which we choose to operate.

Commodity Pricing and Risk Management Activities. Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil. Declines in oil and gas prices may have a material adverse effect on our financial condition, liquidity,

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ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially trigger an impairment under ASC 360, “Property, Plant, and Equipment.” Because our reserves are predominantly natural gas, changes in natural gas prices may have a more significant impact on our financial results.

The majority of our production is sold at market responsive prices. Generally, if the related commodity index falls, the price that we receive for our production will also decline. Therefore, the amount of revenue that we realize is partially determined by factors beyond our control. However, management may mitigate this price risk on all or a portion of our anticipated production with the use of derivative financial instruments. Most recently, we have used financial instruments such as price collars and swap arrangements to reduce the impact of declining prices on our revenue. Under both arrangements, there is also a risk that the movement of index prices may result in our inability to realize the full benefit of an improvement in market conditions.

Settlement of Dispute. In December 2008, we settled a dispute with a third party and as a result recorded a gain of $51.9 million. The dispute involved the propriety of possession of our intellectual property by a third party. The settlement was comprised of $20.2 million in cash paid by the third party to us and $31.7 million related to the fair value of unproved property rights transferred by the third party to us. The fair market value of the unproved property rights was determined based on observable market costs and conditions over a recent time period. Values were pro-rated by property based on the primary term remaining on the properties.

Recently Adopted Accounting Standards

In February 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-09, “Subsequent Events,” which amends ASC 855 to eliminate the requirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and its adoption had no impact on the Company’s financial position, results of operations or cash flows.

Effective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, the Company will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on the Company’s financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please refer to Note 14.

Forward-Looking Information

The statements regarding future financial and operating performance and results, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and

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uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

RESULTS OF OPERATIONS

2010 and 2009 Compared

We reported net income for 2010 of $103.4 million, or $0.99 per share. During 2009, we reported net income of $148.3 million, or $1.43 per share. Net income decreased in 2010 by $45.0 million, primarily due to increased operating, income tax and interest expenses and decreased operating revenues partially offset by increased gain on sale of assets. Operating revenues decreased by $35.2 million largely due to decreases in natural gas and brokered natural gas revenues, partially offset by an increase in crude oil and condensate revenues. Operating expenses increased by $90.2 million between periods due primarily to increases in depreciation, depletion and amortization, impairment of oil and gas properties and other assets, general and administrative expense and direct operations. These increases were partially offset by decreases in brokered natural gas cost, taxes other than income and exploration expense.

Revenue, Price and Volume Variances

Below is a discussion of revenue, price and volume variances.

	Year Ended December 31,				Variance
	2010		2009		Amount		Percent
Revenue Variances (In thousands)
Natural Gas(1)	$	694,803	$	731,688	$	(36,885)		(5	%)
Brokered Natural Gas		65,281		75,283		(10,002)		(13	%)
Crude Oil and Condensate		79,091		69,936		9,155		13	%
Other		5,086		4,323		763		18	%

⁽¹⁾ Natural Gas Revenues exclude the unrealized loss from the change in fair value of our basis swaps of $0.2 million and $2.0 million in 2010 and 2009, respectively.

	Year Ended December 31,				Variance						Increase (Decrease) (In thousands)
	2010		2009		Amount			Percent
Price Variances
Natural Gas(1)	$	5.54	$	7.47	$	(1.93	)		(26	%)	$	(242,758	)
Crude Oil and Condensate(2)	$	97.91	$	85.52	$	12.39			14	%		10,010
Total											$	(232,748	)
Volume Variances
Natural Gas (Mmcf)		125,474		97,914		27,560			28	%	$	205,873
Crude Oil and Condensate (Mbbl)		808		818		(10	)		(1	%)		(855	)
Total											$	205,018

⁽¹⁾ These prices include the realized impact of derivative instrument settlements, which increased the price by $1.23 per Mcf in 2010 and by $3.80 per Mcf in 2009.

⁽²⁾ These prices include the realized impact of derivative instrument settlements, which increased the price by $22.31 per Bbl in 2010 and by $28.85 per Bbl in 2009.

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Natural Gas Revenues

The decrease in Natural Gas Revenue of $36.9 million, excluding the impact of the unrealized gains and losses discussed above, is due primarily to the decrease in realized natural gas prices, decreased production in the South region associated with normal production declines, delays in completions and a shift from gas to oil projects, as well as the sale of our Canadian properties in April 2009. Partially offsetting these decreases was an increase in natural gas production in the North region associated with increased drilling and the start up of a portion of the Lathrop compressor station in the Marcellus shale at the end of the second quarter of 2010.

Crude Oil and Condensate Revenues

The $9.2 million increase in crude oil and condensate revenues is primarily due to an increase in realized crude oil prices and an increase in crude oil production in the South region associated with the Eagle Ford shale and Pettet formation production. These increases are partially offset by lower production in the North region as well as the sale of our Canadian properties in April 2009.

Brokered Natural Gas Revenue and Cost

	Year Ended December 31,				Variance						Price and Volume Variances (In thousands)
	2010		2009		Amount			Percent
Brokered Natural Gas Sales
Sales Price ($/Mcf)	$	5.41	$	5.95	$	(0.54	)		(9	%)	$	(6,527	)
Volume Brokered (Mmcf)	x	12,072	x	12,656		(584	)		(5	%)		(3,475	)
Brokered Natural Gas Revenues (In thousands)	$	65,281	$	75,283							$	(10,002	)
Brokered Natural Gas Purchases
Purchase Price ($/Mcf)	$	4.68	$	5.30	$	(0.62	)		(12	%)	$	7,489
Volume Brokered (Mmcf)	x	12,072	x	12,656		(584	)		(5	%)		3,075
Brokered Natural Gas Cost (In thousands)	$	56,466	$	67,030							$	10,564
Brokered Natural Gas Margin (In thousands)	$	8,815	$	8,253							$	562

The increased brokered natural gas margin of $0.6 million is a result of a lesser decrease in sales price than in purchase price, partially offset by a decrease in volumes brokered.

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Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:

	Year Ended December 31,
	2010					2009
(In thousands)	Realized		Unrealized			Realized		Unrealized
Operating Revenues—Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas	$	154,960	$	—		$	371,915	$	—
Crude Oil		18,030		—			23,112		—
Total Cash Flow Hedges		172,990		—			395,027		—
Other Derivative Financial Instruments
Natural Gas Basis Swaps		—		(226	)		—		(1,954	)
Total Other Derivative Financial Instruments		—		(226	)		—		(1,954	)
Total Cash Flow Hedges and Other Derivative Financial Instruments	$	172,990	$	(226	)	$	395,027	$	(1,954	)

Operating and Other Expenses

	Year Ended December 31,					Variance
(In thousands)	2010			2009		Amount			Percent
Operating and Other Expenses
Brokered Natural Gas Cost	$	56,466		$	67,030	$	(10,564	)		(16	%)
Direct Operations—Field and Pipeline		99,642			93,985		5,657			6	%
Taxes Other Than Income		37,894			44,649		(6,755	)		(15	%)
Exploration		42,725			50,784		(8,059	)		(16	%)
Depreciation, Depletion and Amortization		327,083			251,260		75,823			30	%
Impairment of Oil and Gas Properties and Other Assets		40,903			17,622		23,281			132	%
General and Administrative		79,177			68,374		10,803			16	%
Total Operating Expense	$	683,890		$	593,704	$	90,186			15	%
(Gain) / Loss on Sale of Assets	$	(106,294	)	$	3,303	$	(109,597	)		(3,318	%)
Interest Expense and Other		67,941			58,979		8,962			15	%
Income Tax Expense		95,112			74,947		20,165			27	%

Total costs and expenses from operations increased by $90.2 million from 2009 to 2010. The primary reasons for this fluctuation are as follows:

• Depreciation, Depletion and Amortization increased by $75.8 million from 2009 to 2010, primarily due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes. Amortization of unproved properties increased $17.6 million primarily due to increased unproved leasehold costs in the Marcellus shale and the Eagle Ford shale in south Texas in late 2009 and continuing into 2010.

• Impairment of Oil & Gas Properties and Other Assets increased by $23.3 million from 2009 to 2010. Impairments in 2010 consisted of a $35.8 million impairment of two south Texas fields due to continued price declines and limited activity and a $5.1 million impairment related to drilling and service equipment.

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• General and Administrative expenses increased by $10.8 million from 2009 to 2010. The increase is primarily due to a $9.9 million increase in legal expenses primarily related to the December 2010 PaDEP settlement, ongoing litigation and related legal fees, a $8.3 million increase in pension expense primarily due to termination and amendment of our pension plans and a $2.4 million increase in incentive compensation. These increases were partially offset by an $8.5 million decrease in stock compensation expense primarily due to prior year awards that fully vested in February 2010 and a reduction in stock price.

• Brokered Natural Gas Cost decreased by $10.6 million from 2009 to 2010. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

• Exploration expense decreased by $8.1 million from 2009 to 2010 primarily due to lower dry hole costs as a result of drilling one dry hole in 2010 compared to two dry holes in 2009. The decrease was partially offset by higher geophysical and geological expenses associated with seismic purchases related to our Marcellus, Eagle Ford and Haynesville shale properties during 2010.

• Taxes Other Than Income decreased by $6.8 million from 2009 to 2010 primarily due to decreased production and ad valorem taxes due to lower natural gas prices and property values partially offset by increased business and occupational taxes and franchise taxes.

• Direct Operations expenses increased by $5.7 million from 2009 to 2010 primarily due to lease maintenance expense in both the North and South regions and plug and abandonment costs in the North region related to plugging and abandoning three vertical wells in accordance with the PaDEP’s Second Modified Consent Order.

Gain / (Loss) on Sale of Assets

Gain / (Loss) on Sale of Assets increased by $109.6 million from 2009 to 2010. During 2010, we recognized a gain of $49.3 million from the sale of our Pennsylvania gathering infrastructure, $40.7 million from the sale of our investment in Tourmaline, $10.8 million from the sale of certain oil and gas properties in the Texas Panhandle, $10.3 million on the sale of our Woodford shale properties, partially offset by an impairment loss of $5.1 million on certain oil and gas properties in Colorado.

During 2009, we recognized a $16.0 million loss on sale of assets primarily due to the sale of the Canadian properties, partially offset by a $12.7 million gain on sale of assets related to the sale of our Thornwood properties in the North region.

Interest Expense, Net

Interest expense, net increased by $9.0 million from 2009 to 2010 primarily due to an increase in weighted-average borrowings under our credit facility based on daily balances of approximately $340.4 million during 2010 compared to approximately $166 million during 2009, and to a lesser extent to the $175.0 million of debt we issued in December 2010. The weighted-average effective interest rate on the credit facility decreased to approximately 3.8% during 2010 compared to approximately 4.0% during 2009. Interest expense in 2010 also includes a make-whole premium payment of $2.8 million associated with the early payment of $75.0 million of the 7.33% fixed rate notes that were due in July 2011.

Income Tax Expense

Income tax expense increased by $20.2 million due to a higher effective tax rate offset by a decrease in our pre-tax income. The effective tax rates for 2010 and 2009 were 47.9% and 33.6%, respectively. The effective tax rate was higher primarily due to an increase in our state rates used in establishing deferred income taxes mainly due to a shift in our state apportionment factors to higher rate states, primarily in Pennsylvania, as a result of our increased focus on development of our Marcellus shale properties.

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2009 and 2008 Compared

We reported net income for 2009 of $148.3 million, or $1.43 per share. During 2008, we reported net income of $211.3 million, or $2.10 per share. Net income decreased in 2009 by $63.0 million, primarily due to decreased operating revenues and increased operating expenses, partially offset by increased gain on sale of assets. Operating revenues decreased by $66.5 million largely due to decreases in brokered natural gas and natural gas revenues. Operating expenses decreased by $33.1 million between periods due primarily to decreases in brokered natural gas costs, taxes other than income and general and administrative expenses, partially offset by increased depreciation, depletion and amortization, exploration expense and direct operations. In addition, net income was impacted in 2009 by higher interest expense, decreased income tax expense and, to a lesser extent, loss on sale of assets. Income tax expense was lower in 2009 as a result of a decrease in operating income, as discussed above, and a decrease in the effective tax rate. The decrease in the effective tax rate is primarily due to an overall reduction in state deferred tax liabilities and tax benefits associated with foreign tax credits.

Revenue, Price and Volume Variances

Below is a discussion of revenue, price and volume variances.

	Year Ended December 31,				Variance
	2009		2008		Amount			Percent
Revenue Variances (In thousands)
Natural Gas(1)	$	731,688	$	758,755	$	(27,067	)		(4	%)
Brokered Natural Gas		75,283		114,220		(38,937	)		(34	%)
Crude Oil and Condensate		69,936		69,711		225			0	%
Other		4,323		3,105		1,218			39	%

⁽¹⁾ Natural Gas Revenues exclude the unrealized loss from the change in fair value of our basis swaps of $2.0 million in 2009. There was no impact from the unrealized change in natural gas derivative fair value for 2008.

	Year Ended December 31,				Variance						Increase (Decrease) (In thousands)
	2009		2008		Amount			Percent
Price Variances
Natural Gas(1)	$	7.47	$	8.39	$	(0.92	)		(11	%)	$	(89,606	)
Crude Oil and Condensate (2)	$	85.52	$	89.11	$	(3.59	)		(4	%)		(2,966	)
Total											$	(92,572	)
Volume Variances
Natural Gas (Mmcf)		97,914		90,425		7,489			8	%	$	62,539
Crude Oil and Condensate (Mbbl)		818		782		36			5	%		3,191
Total											$	65,730

⁽¹⁾ These prices include the realized impact of derivative instrument settlements, which increased the price by $3.80 per Mcf in 2009 and by $0.20 per Mcf in 2008.

⁽²⁾ These prices include the realized impact of derivative instrument settlements, which increased the price by $28.25 per Bbl in 2009 and decreased the price by $6.33 per Bbl in 2008.

Natural Gas Revenues

The decrease in Natural Gas Revenue of $27.1 million, excluding the impact of the unrealized gains and losses discussed above, is almost entirely due to the sale of our Canadian properties and a decrease in realized natural gas prices that was essentially offset by an increase in natural gas production. This increase in natural gas

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production was primarily a result of increased production in the North region associated with the initiation of production in Susquehanna County, Pennsylvania in the third quarter of 2008 and increased drilling in the Marcellus shale prospect in Susquehanna County as well as increased natural gas production in the South region associated with the properties we acquired in east Texas in August 2008 and drilling in the Angie field. Partially offsetting these production gains were decreases in production in Canada due to the sale of substantially all of our Canadian properties in April 2009.

Crude Oil and Condensate Revenues

The increase in crude oil production, partially offset by a decrease in realized crude oil prices, resulted in a net revenue increase of $0.2 million. The increase in crude oil production was primarily the result of increased production in the South region associated with the properties we acquired in the east Texas acquisition in August 2008 and an increase related to Pettet formation production in the Angie field, partially offset by a decrease in production in Canada due to the sale of substantially all of our Canadian properties in April 2009.

Brokered Natural Gas Revenue and Cost

	Year Ended December 31,				Variance						Price and Volume Variances (In thousands)
	2009		2008		Amount			Percent
Brokered Natural Gas Sales
Sales Price ($/Mcf)	$	5.95	$	10.39	$	(4.44	)		(43	%)	$	(56,185	)
Volume Brokered (Mmcf)	x	12,656	x	10,996		1,660			15	%		17,248
Brokered Natural Gas Revenues (In thousands)	$	75,283	$	114,220							$	(38,937	)
Brokered Natural Gas Purchases
Purchase Price ($/Mcf)	$	5.30	$	9.14	$	(3.84	)		(42	%)	$	48,592
Volume Brokered (Mmcf)	x	12,656	x	10,996		1,660			15	%		(15,173	)
Brokered Natural Gas Cost (In thousands)	$	67,030	$	100,449							$	33,419
Brokered Natural Gas Margin (In thousands)	$	8,253	$	13,771							$	(5,518	)

The decreased brokered natural gas margin of $5.5 million is a result of a decrease in sales price that outpaced the decrease in purchase price, partially offset by an increase in volumes brokered.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:

	Year Ended December 31,
	2009					2008
(In thousands)	Realized		Unrealized			Realized			Unrealized
Operating Revenues—Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	371,915	$	—		$	17,972		$	—
Crude Oil		23,112		—			(4,951	)		—
Total Cash Flow Hedges		395,027		—			13,021			—
Other Derivative Financial Instruments
Natural Gas Basis Swaps		—		(1,954	)		—			—
Total Other Derivative Financial Instruments		—		(1,954	)		—			—
Total Cash Flow Hedges and Other Derivative Financial Instruments	$	395,027	$	(1,954	)	$	13,021		$	—

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Operating and Other Expenses

	Year Ended December 31,					Variance
(In thousands)	2009		2008			Amount			Percent
Operating and Other Expenses
Brokered Natural Gas Cost	$	67,030	$	100,449		$	(33,419	)		(33	%)
Direct Operations—Field and Pipeline		93,985		91,839			2,146			2	%
Taxes Other Than Income		44,649		66,540			(21,891	)		(33	%)
Exploration		50,784		31,200			19,584			63	%
Depreciation, Depletion and Amortization		251,260		226,915			24,345			11	%
Impairment of Oil and Gas Properties and Other Assets		17,622		35,700			(18,078	)		(51	%)
General and Administrative		68,374		74,185			(5,811	)		(8	%)
Total Operating Expense	$	593,704	$	626,828		$	(33,124	)		(5	%)
(Gain) / Loss on Sale of Assets	$	3,303	$	(1,143	)	$	4,446			389	%
Interest Expense and Other		58,979		36,389			22,590			62	%
Income Tax Expense		74,947		124,333			(49,386	)		(40	%)

Total costs and expenses from operations decreased by $33.1 million in 2009 from 2008. The primary reasons for this fluctuation are as follows:

• Brokered Natural Gas Cost decreased by $33.4 million from 2008 to 2009. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

• Depreciation, Depletion and Amortization increased by $24.3 million from 2008 to 2009. This is primarily due to the impact on the DD&A rate of higher capital costs and higher natural gas and oil production volumes, including the east Texas acquisition in August 2008. Amortization of unproved properties decreased by $11.5 million from 2008 to 2009, primarily due to the $17.0 million impairment of Mississippi, Montana and North Dakota leases in 2008 offset by increased lease acquisition costs incurred in several exploratory and developmental areas in the North and in east Texas as well as the amortization of undeveloped costs associated with the east Texas acquisition in August 2008.

• Taxes Other Than Income decreased by $21.9 million from 2008 to 2009 due to lower production taxes as a result of lower average natural gas and crude oil prices.

• Exploration expense increased by $19.6 million from 2008 to 2009 primarily due to higher charges for idle contract rigs and higher dry hole and geological and geophysical costs.

• Impairment of Oil & Gas Properties and Other Assets decreased by $18.1 million from 2008 to 2009. Impairments in 2009 consisted of approximately $12.0 million in the Fossil Federal field in San Miguel County, Colorado resulting from lower well performance and $5.6 million in the Beaurline field in Hidalgo County, Texas resulting from lower well performance.

• General and Administrative expenses decreased by $5.8 million from 2008 to 2009. This is primarily due to decreased stock compensation expense largely related to a reduction in supplemental employee compensation expense of $14.7 million, partially offset by an increase in performance share award expense of $5.5 million and an increase in pension expense related to our qualified pension plan.

• Direct Operations expenses increased by $2.1 million from 2008 to 2009 primarily due to higher personnel and labor expenses, increased severance and employee relocation costs associated with the reorganization of operations and higher compressor and outside operated properties charges.

Interest Expense, Net

Interest expense, net increased by $22.6 million from 2008 to 2009 primarily due to increased interest expense related to the $492 million principal amount of debt we issued in our July and December 2008 private

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placements. Weighted-average borrowings under our credit facility based on daily balances were approximately $166 million during 2009 compared to approximately $172 million during 2008. The weighted-average effective interest rate on the credit facility decreased to approximately 4.0% during 2009 compared to approximately 4.8% during 2008.

Income Tax Expense

Income tax expense decreased by $49.4 million due to a decrease in our pre-tax income. The effective tax rates for 2009 and 2008 were 33.6% and 37.0%, respectively. The decrease in the effective tax rate is primarily due to an overall reduction in state deferred tax liabilities and tax benefits associated with foreign tax credits.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Our primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

The capital markets continue to be volatile with periods of easy access and times with unfavorable conditions. As a result of the volatility in the capital markets and our increased level of borrowings, we may at times experience increased costs associated with future borrowings and debt issuances based on recent financings. At this time, we do not believe our liquidity has been materially affected by market events.

Derivative Instruments and Hedging Activity

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the hedges. Please read the discussion below as well as Note 13 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

Periodically, we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. As of December 31, 2010, we had 11 derivative contracts open: four natural gas price swap arrangements, six natural gas basis swaps arrangements and one crude oil price collar arrangement. During 2010, we entered into a total of six new derivative contracts including one crude oil swap contract for 2010, four natural gas swap contracts for 2011 and one crude oil collar contract for 2011.

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As of December 31, 2010, we had the following outstanding commodity derivatives:

Commodity and Derivative Type	Weighted-Average Contract Price	Volume		Contract Period	Net Unrealized Gain / (Loss) (In thousands)
Derivatives Designated as Hedging Instruments
Natural Gas Swaps	$6.24 per Mcf		12,909 Mmcf	January - December 2011	$	18,669
Crude Oil Collars	$93.25 Ceiling /$80.00 Floor per Bbl		365 Mbbl	January - December 2011		(1,743	)
					$	16,926
Derivatives Not Designated as Hedging Instruments
Natural Gas Basis Swaps	$(0.27) per Mcf		16,123 Mmcf	January - December 2012		(2,180	)
					$	14,746

The amounts set forth under the net unrealized gain / (loss) column in the tables above represent our total unrealized derivative position at December 31, 2010 and include the impact of nonperformance risk. Nonperformance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions.

From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

During 2010, natural gas price swaps covered 35.9 Bcf, or 29%, of our 2010 gas production at an average price of $9.30 per Mcf. We had two crude oil price swaps covering 730 Mbbl, or 90%, of our 2010 oil production at an average price of $104.25 per Bbl.

During 2010, we also entered into crude oil swaps to hedge our price exposure on our 2010 production, natural gas swaps to hedge our price exposure on our 2011 production and crude oil price collars to hedge our price exposure on our 2011 production. In addition, we also have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting.

We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our financial results due to non-performance by third parties. Our primary derivative contract counterparties are Bank of Montreal, JPMorgan, Bank of America and BNP Paribas.

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details.

Fair Market Value of Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the short-term maturities of these instruments.

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The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is our default or repayment risk. The credit spread (premium or discount) is determined by comparing our fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes and the credit facility is based on interest rates currently available to the us.

We use available marketing data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:

	December 31, 2010				December 31, 2009
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-Term Debt	$	975,000	$	1,100,830	$	805,000	$	863,559

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		55
Consolidated Statement of Operations for the Years Ended December 31, 2010, 2009 and 2008		56
Consolidated Balance Sheet at December 31, 2010 and 2009		57
Consolidated Statement of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		58
Consolidated Statement of Stockholders’ Equity for the Years Ended December  31, 2010, 2009 and 2008		59
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008		60
Notes to the Consolidated Financial Statements		61
Supplemental Oil and Gas Information (Unaudited)		105
Quarterly Financial Information (Unaudited)		110

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Cabot Oil & Gas Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, stockholders’ equity, comprehensive income and of cash flows present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries (the “Company”) at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective 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 (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/    PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2011

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

	Year Ended December 31,
(In thousands, except per share amounts)	2010		2009			2008
OPERATING REVENUES
Natural Gas	$	694,577	$	729,734		$	758,755
Brokered Natural Gas		65,281		75,283			114,220
Crude Oil and Condensate		79,091		69,936			69,711
Other		5,086		4,323			3,105
		844,035		879,276			945,791
OPERATING EXPENSES
Brokered Natural Gas Cost		56,466		67,030			100,449
Direct Operations—Field and Pipeline		99,642		93,985			91,839
Taxes Other Than Income		37,894		44,649			66,540
Exploration		42,725		50,784			31,200
Depreciation, Depletion and Amortization		327,083		251,260			226,915
Impairment of Oil & Gas Properties and Other Assets		40,903		17,622			35,700
General and Administrative		79,177		68,374			74,185
		683,890		593,704			626,828
Gain/(Loss) on Sale of Assets		106,294		(3,303	)		1,143
Gain on Settlement of Dispute		—		—			51,906
INCOME FROM OPERATIONS		266,439		282,269			372,012
Interest Expense and Other		67,941		58,979			36,389
Income Before Income Taxes		198,498		223,290			335,623
Income Tax Expense		95,112		74,947			124,333
NET INCOME	$	103,386	$	148,343		$	211,290
Earnings Per Share
Basic	$	0.99	$	1.43		$	2.10
Diluted	$	0.98	$	1.42		$	2.08
Weighted-Average Common Shares Outstanding
Basic		103,911		103,616			100,737
Diluted		105,195		104,683			101,726
Dividends Per Common Share	$	0.12	$	0.12		$	0.12

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEET

	December 31,			December 31,
(In thousands, except share amounts)	2010			2009
ASSETS
Current Assets
Cash and Cash Equivalents	$	55,949		$	40,158
Accounts Receivable, Net		94,488			80,362
Income Taxes Receivable		—			8,909
Inventories		29,667			27,990
Derivative Instruments		16,926			114,686
Other Current Assets		5,978			9,397
Total Current Assets		203,008			281,502
Properties and Equipment, Net (Successful Efforts Method)		3,762,760			3,358,199
Other Assets		39,263			43,700
	$	4,005,031		$	3,683,401
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	229,981		$	215,588
Income Taxes Payable		25,957			—
Accrued Liabilities		47,897			58,049
Deferred Income Taxes		—			35,104
Total Current Liabilities		303,835			308,741
Pension and Postretirement Benefits		34,053			54,835
Long-Term Debt		975,000			805,000
Deferred Income Taxes		714,953			644,801
Asset Retirement Obligation		72,311			29,676
Other Liabilities		32,179			27,834
Total Liabilities		2,132,331			1,870,887
Commitments and Contingencies (Note 8)
Stockholders’ Equity
Common Stock:
Authorized—240,000,000 Shares of $0.10 Par Value in 2010 and 2009
Issued—104,210,084 Shares and 103,856,447 Shares in 2010 and 2009, respectively		10,421			10,386
Additional Paid-in Capital		720,920			705,569
Retained Earnings		1,148,391			1,057,472
Accumulated Other Comprehensive Income / (Loss)		(3,683	)		42,436
Less Treasury Stock, at Cost: 202,200 Shares in 2010 and 2009, respectively		(3,349	)		(3,349	)
Total Stockholders’ Equity		1,872,700			1,812,514
	$	4,005,031		$	3,683,401

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

	Year Ended December 31,
(In thousands)	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	103,386		$	148,343		$	211,290
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		327,083			251,260			226,915
Impairment of Oil & Gas Properties and Other Assets		40,903			17,622			35,700
Deferred Income Tax Expense		61,809			101,815			120,851
(Gain) / Loss on Sale of Assets		(106,294	)		3,303			(1,143	)
Gain on Settlement of Dispute		—			—			(31,706	)
Exploration Expense		11,657			50,784			31,200
Unrealized Loss on Derivatives		226			1,954			—
Amortization of Debt Issuance Cost		3,381			3,635			634
Stock-Based Compensation Expense and Other		15,413			25,924			14,989
Changes in Assets and Liabilities:
Accounts Receivable, Net		(14,125	)		28,725			(3,928	)
Inventories		(1,677	)		17,687			(18,324	)
Other Current Assets		3,675			3,103			10,816
Other Assets and Other Liabilities		6,204			531			6,422
Accounts Payable and Accrued Liabilities		(1,488	)		(27,202	)		3,321
Income Taxes		34,866			358			38,101
Stock-Based Compensation Tax Benefit		(108	)		(13,790	)		(10,691	)
Net Cash Provided by Operating Activities		484,911			614,052			634,447
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(857,251	)		(610,813	)		(848,640	)
Acquisitions		—			(394	)		(605,748	)
Proceeds from Sale of Assets		243,510			80,180			2,099
Net Cash Used in Investing Activities		(613,741	)		(531,027	)		(1,452,289	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from Debt		525,000			105,000			892,000
Repayments of Debt		(355,000	)		(167,000	)		(375,000	)
Net Proceeds from Sale of Common Stock		801			83			316,230
Stock-Based Compensation Tax Benefit		108			13,790			10,691
Dividends Paid		(12,467	)		(12,432	)		(12,073	)
Capitalized Debt Issuance Costs		(13,821	)		(10,409	)		(4,403	)
Net Cash Provided by / (Used in) Financing Activities		144,621			(70,968	)		827,445
Net Increase in Cash and Cash Equivalents		15,791			12,057			9,603
Cash and Cash Equivalents, Beginning of Period		40,158			28,101			18,498
Cash and Cash Equivalents, End of Period	$	55,949		$	40,158		$	28,101

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands, except per share amounts)	Common Shares			Stock Par			Treaury Shares			Treasury Stock			Paid-In Capital			Accumulated Other Comprehensive Income / (Loss)			Retained Earnings			Total
Balance at December 31, 2007		102,681		$	10,268			5,205		$	(85,690	)	$	424,229		$	(894	)	$	722,344		$	1,070,257
Net Income		—			—			—			—			—			—			211,290			211,290
Exercise of Stock Options		328			33			—			—			2,692			—			—			2,725
Retirement of Treasury Stock		(5,003	)		(500	)		(5,003	)		82,341			(81,841	)		—			—			—
Tax Benefit of Stock-Based Compensation		—			—			—			—			10,691			—			—			10,691
Stock Amortization and Vesting		418			42			—			—			6,545			—			—			6,587
Stock Held in Rabbi Trust		64			6			—			—			(3,198	)		—			—			(3,192	)
Stock Issued for Drilling Company Acquisition		70			7			—			—			3,493			—			—			3,500
Issuance of Common Stock		5,003			500			—			—			312,957			—			—			313,457
Cash Dividends at $0.12 per Share		—			—			—			—			—			—			(12,073	)		(12,073	)
Other Comprehensive Income / (Loss)		—			—			—			—			—			187,320			—			187,320
Balance at December 31, 2008		103,561		$	10,356			202		$	(3,349	)	$	675,568		$	186,426		$	921,561		$	1,790,562
Net Income		—			—			—			—			—			—			148,343			148,343
Exercise of Stock Options and
Stock Appreciation Rights		14			2			—			—			53			—			—			55
Tax Benefit of Stock-Based Compensation		—			—			—			—			13,790			—			—			13,790
Stock Amortization and Vesting		281			28			—			—			14,898			—			—			14,926
Sale of Stock Held in Rabbi Trust		—			—			—			—			1,260			—			—			1,260
Cash Dividends at $0.12 per Share		—			—			—			—			—			—			(12,432	)		(12,432	)
Other Comprehensive Income / (Loss)		—			—			—			—			—			(143,990	)		—			(143,990	)
Balance at December 31, 2009		103,856		$	10,386			202		$	(3,349	)	$	705,569		$	42,436		$	1,057,472		$	1,812,514
Net Income		—			—			—			—			—			—			103,386			103,386
Exercise of Stock Options and
Stock Appreciation Rights		39			4			—			—			766			—			—			770
Tax Benefit of Stock-Based Compensation		—			—			—			—			108			—			—			108
Stock Amortization and Vesting		315			31			—			—			12,899			—			—			12,930
Sale of Stock Held in Rabbi Trust		—			—			—			—			1,578			—			—			1,578
Cash Dividends at $0.12 per Share		—			—			—			—			—			—			(12,467	)		(12,467	)
Other Comprehensive Income / (Loss)		—			—			—			—			—			(46,119	)		—			(46,119	)
Balance at December 31, 2010		104,210		$	10,421			202		$	(3,349	)	$	720,920		$	(3,683	)	$	1,148,391		$	1,872,700

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

	Year Ended December 31,
(In thousands)	2010					2009						2008
Net Income			$	103,386					$	148,343					$	211,290
Other Comprehensive Income / (Loss), net of taxes:
Reclassification Adjustment for Settled Contracts, net of taxes of $65,734, $147,048 and $4,844, respectively				(107,256	)					(247,979	)					(8,177	)
Changes in Fair Value of Hedge Positions, net of taxes of $(29,777), $(57,303) and $(134,259), respectively				45,878						96,783						226,692
Defined Benefit Pension and Postretirement Plans:
Net Gain / (Loss) Arising During the Year, net of taxes of $(3,245), $1,773 and $10,445, respectively	$	5,693				$	(3,009	)				$	(17,629	)
Effect of Plan Termination and Amendment, net of taxes of $(310), $0 and $0, respectively		506					—						—
Settlement, net of taxes of $(1,528), $0 and $0, respectively		2,493					—						—
Amortization of Net Obligation at Transition, net of taxes of $(240), $(236) and $(234), respectively		392					396						398
Amortization of Prior Service Cost, net of taxes of $(217), $(267) and $(373), respectively		355					450						630
Amortization of Net Loss, net of taxes of $(3,548), $(1,432) and $(603), respectively		5,788		15,227			2,422			259			1,020			(15,581	)
Foreign Currency Translation Adjustment, net of taxes of $(20), $(4,116) and $9,292, respectively				32						6,947						(15,614	)
Total Other Comprehensive Income / (Loss)				(46,119	)					(143,990	)					187,320
Comprehensive Income			$	57,267					$	4,353					$	398,610

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

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Nature of Operations

Cabot Oil & Gas Corporation and its subsidiaries are engaged in the development, exploitation, exploration, production and marketing of natural gas, crude oil and, to a lesser extent, natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The Company operates in one segment, natural gas and oil development, exploitation and exploration, exclusively within the continental United States. The Company’s exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs.

Certain reclassifications have been made to prior year statement to conform with current year presentation. These reclassifications have no impact on net income.

In 2009, the Company reorganized its operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with its Texas and Louisiana areas to form the South region. Additionally, the Company exited Canada through the sale of its properties in April 2009. Prior to the third quarter of 2009, the Company presented the geographic areas as East, Gulf Coast, West and Canada.

The consolidated financial statements contain the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions.

Recently Adopted Accounting Standards

In February 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-09, “Subsequent Events,” which amends Accounting Standards Codification (ASC) 855 to eliminate the requirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and its adoption had no impact on the Company’s financial position, results of operations or cash flows.

Effective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, the Company will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on the Company’s financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please refer to Note 14.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents were primarily concentrated in one financial institution at December 31, 2010 and 2009. The Company periodically assesses the financial condition of these institutions and considers any possible credit risk to be minimal.

Inventories

Inventories are comprised of natural gas in storage, tubular goods and well equipment and pipeline imbalances. All inventory balances are carried at the lower of average cost or market.

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Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net pipeline imbalance is included in inventory in the Consolidated Balance Sheet.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts for receivables that the Company determines to be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against Accounts Receivable in the Consolidated Balance Sheet, was $4.1 million and $3.6 million at December 31, 2010 and 2009, respectively.

Accounts Payable

This account may include credit balances from outstanding checks in zero balance cash accounts. These credit balances are referred to as book overdrafts and are included as a component of Accounts Payable on the Consolidated Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in Accounts Payable at December 31, 2010 and 2009 as sufficient cash was available for offset.

Properties and Equipment

The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells and successful exploratory drilling costs to locate proved reserves are capitalized.

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and ii) drilling of the additional exploratory wells is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to exploration expense.

Development costs of proved oil and gas properties, including estimated dismantlement, restoration and abandonment costs and acquisition costs, are depreciated and depleted on a field basis by the units-of-production method using proved developed and proved reserves, respectively. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Generally pipeline and transmission systems are depreciated over 12 to 25 years, gathering and compression equipment is depreciated over 10 years and storage equipment and facilities are depreciated over 10 to 16 years. Certain other assets are depreciated on a straight-line basis over 3 to 10 years. Buildings are depreciated on a straight-line basis over 25 to 40 years.

Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not

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significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.

The Company evaluates the impairment of its oil and gas properties and other assets whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on estimates of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. Fair value is calculated by discounting the future cash flows. The discount factor used is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil. During 2010, 2009 and 2008, the Company recorded total impairments of $40.9 million, $17.6 million and $31.3 million (excluding the impairment of $4.4 million of goodwill), respectively.

Costs attributable to the Company’s unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past drilling and development experience and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset’s useful life. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities are also recorded for meter stations, pipelines, processing plants and compressors. At December 31, 2010, there were no assets legally restricted for purposes of settling asset retirement obligations.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included within Depreciation, Depletion and Amortization expense on the Company’s Consolidated Statement of Operations.

Risk Management Activities

From time to time, the Company enters into derivative contracts, such as natural gas and crude oil price swaps or zero-cost price collars, as a hedging strategy to manage commodity price risk associated with its production or other contractual commitments. All hedge transactions are subject to the Company’s risk management policy which does not permit speculative trading activities. Gains or losses on these hedging activities are generally recognized over the period that its production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contract not considered a hedge are recognized currently in the results of operations.

When the designated item associated with a derivative instrument matures or is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to

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occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge.

Effective January 1, 2009, the Company adopted the amended disclosure requirements prescribed in ASC 815, “Derivatives and Hedging.”

Revenue Recognition

Gas Imbalance

The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded at the actual price realized upon the gas sale in Accounts Payable in the Consolidated Balance Sheet if the Company’s excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties.

Brokered Natural Gas Margin

The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses in accordance with ASC 605-45, “Revenue Recognition: Principle Agent Considerations”. The Company realizes brokered margin as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company and/or the counterparty takes title to the natural gas purchased or sold. The Company realized $8.8 million, $8.3 million and $13.8 million of brokered natural gas margin in 2010, 2009 and 2008, respectively.

Natural Gas Measurement

The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties.

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The Company recognizes accrued interest related to uncertain tax positions in Interest Expense and Other expense and accrued penalties related to such positions in General and Administrative expense in the Consolidated Statement of Operations.

Stock-Based Compensation

The Company accounts for stock-based compensation under a fair value based method of accounting prescribed under ASC 718. Under the fair value method, compensation cost is measured at the grant date and remeasured each reporting period for liability-classified awards based on the fair value of an award and is recognized over the service period, which is usually the vesting period. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. Stock-based compensation cost for all types of awards is included in General and Administrative Expense in the Consolidated Statement of Operations.

The tax benefit for stock-based compensation is included as both a cash inflow from financing activities and a cash outflow from operating activities in the Consolidated Statement of Cash Flows. In accordance with ASC 718, the Company recognizes a tax benefit only to the extent it reduces the Company’s income taxes payable. For the years ended December 31, 2010, 2009 and 2008, the Company realized tax benefits of $0.1 million, $13.8 million and $10.7 million, respectively.

Environmental Matters

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Any insurance recoveries are recorded as assets when received.

Market Risk

The Company’s primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

The capital markets continue to be volatile with periods of easy access and times with unfavorable conditions. As a result of the volatility in the capital markets and the Company’s increased level of borrowings, it may a times experience increased costs associated with future borrowings and debt issuances based on recent financings. At this time, the Company does not believe its liquidity has been materially affected by market events.

Credit Risk

Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties.

In 2010, one customer accounted for approximately 11% of the Company’s total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively, of the Company’s total sales. In 2008, one customer accounted for approximately 16% of the Company’s total sales.

Use of Estimates

In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and

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liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas, natural gas liquids and crude oil revenues and expenses, current values of derivative instruments, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, asset retirement obligations, pension and postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:

	December 31,
(In thousands)	2010			2009
Proved Oil and Gas Properties	$	4,794,650		$	4,118,005
Unproved Oil and Gas Properties		490,181			423,373
Gathering and Pipeline Systems		237,043			294,755
Land, Building and Other Equipment		86,248			77,474
		5,608,122			4,913,607
Accumulated Depreciation, Depletion and Amortization		(1,845,362	)		(1,555,408	)
	$	3,762,760		$	3,358,199

The following table reflects the net changes in capitalized exploratory well costs during 2010, 2009 and 2008.

	December 31,
(In thousands)	2010			2009			2008
Beginning balance at January 1	$	4,179		$	5,990		$	2,161
Additions to capitalized exploratory well costs pending the determination of proved reserves		4,285			4,179			5,990
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(4,148	)		(762	)		(1,259	)
Capitalized exploratory well costs charged to expense		(31	)		(5,228	)		(902	)
Ending balance at December 31	$	4,285		$	4,179		$	5,990

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:

	December 31,
(In thousands)	2010		2009		2008
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	4,285	$	4,179	$	5,990
Capitalized exploratory well costs that have been capitalized for a period greater than one year		—		—		—
Balance at December 31	$	4,285	$	4,179	$	5,990

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At December 31, 2010, 2009 and 2008, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

In November 2010, the Company recorded an impairment of $5.1 million related to drilling and service equipment that was primarily used in drilling our West Virginia properties. The impairment was a result of decreased activity in West Virginia and the decision to sell the underlying assets. These assets were reduced to fair value of approximately $4.0 million. Fair value was determined using the market approach which considered broker quotes from market participants in the oil field services sector. The estimate was based on significant inputs that were not observable in the market and are considered to be Level 3 inputs as defined in ASC 820.

In September 2010, the Company recorded a $35.8 million impairment of oil and gas properties due to continued price declines and limited activity in two south Texas fields. These fields were reduced to a fair value of approximately $15.4 million using discounted future cash flows.

During 2009, the Company recorded $17.6 million of impairments of oil and gas properties. The Company recorded an impairment of $12.0 million in the Fossil Federal field in San Miguel County, Colorado in the North region resulting from lower well performance and $5.6 million in the Beaurline field in Hidalgo County, Texas in the South region resulting from lower well performance. These fields were reduced to fair value of approximately $8.9 million using discounted future cash flows.

The fair value of the impaired fields was based on significant inputs that were not observable in the market and are considered to be level 3 inputs as defined in ASC 820. Refer to Note 14 for more information and a description of fair value hierarchy. Key assumptions include (1) oil and natural gas prices (adjusted to quality and basis differentials), (2) projections of estimated quantities of oil and gas reserves and production, (3) estimates of future development and production costs and (4) risk adjusted discount rates (14% at September 30, 2010 and 16% at December 31, 2009, respectively).

During 2008, the Company recorded an impairment of approximately $3.0 million in the Corral Creek field in Washakie County, Wyoming in the North region resulting from lower than expected performance from the two well field and $28.3 million in the Trawick field in Rusk County, Texas in the South region resulting from a decline in natural gas prices and higher well costs.

During 2010, 2009 and 2008, amortization of the Company’s unproved properties were $47.6 million, $30.0 million and $41.5 million, respectively and are included in Depreciation, Depletion, and Amortization in the Consolidated Statement of Operations. Included in 2008 amortization was $17.0 million related to three exploratory oil and gas prospects located in Mississippi, Montana and North Dakota that were abandoned. These prospects were abandoned as a result of the significant decline in commodity prices in the fourth quarter of 2008 and the Company’s change in exploration plans for these prospects.

In April 2008, the Company acquired a small oilfield services business for total consideration of $21.6 million, comprised of the conversion of a $15.6 million note receivable, the issuance of 70,168 shares of Company common stock, and the payment of $2.5 million in cash. The transaction was accounted for as a business combination, and the Company recorded approximately $4.4 million of goodwill. In December 2008, the Company fully impaired the goodwill due to the impact of the broad economic downturn and the related reductions in future drilling programs.

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East Texas Property Acquisition

On August 15, 2008, the Company completed the acquisition of certain producing oil and gas properties located in Panola and Rusk counties, Texas in order to expand its position in the Minden field. Total net cash consideration paid by the Company in the transaction was approximately $604.0 million. The east Texas acquisition was recorded using the purchase method of accounting. Financial results for the period from the closing date on August 15, 2008 to December 31, 2009 are included within the Company’s Consolidated Statements of Operations. The following table presents the unaudited pro forma results of operations for the year ended December 31, 2008, as if the acquisition was made at the beginning of the period. These pro forma results are not necessarily indicative of future results, nor do they purport to represent the actual financial results that would have occurred had the acquisition been in effect for the periods presented.

(In thousands, except per share amounts)	Year Ended December 31,  2008
	(Unaudited)
Revenues	$	1,009,412
Net Income	$	218,290
Earnings Per Share:
Basic	$	2.12
Diluted	$	2.10
Weighted-Average Common Shares Outstanding:
Basic		103,142
Diluted		104,131

Disposition of Assets

In December 2010, the Company sold its existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations to Williams Field Services (Williams), a subsidiary of Williams Partners L.P., for $150 million and recognized a $49.3 million gain on sale of assets. Under the terms of the purchase and sale agreement, the Company is obligated to construct pipelines to connect certain of its 2010 program wells, complete the construction of the Lathrop compressor station and complete taps into certain pipeline delivery points. The Company expects to complete these obligations in the first half of 2011. The Company also entered into a 25 year firm gathering contract with Williams that requires Williams to complete construction of approximately 32 miles of high pressure pipeline, 65 miles of trunklines in Susquehanna County, and build two compressor stations in the next two years. Additionally, Williams will connect all of the Company’s drilling program wells, which will connect our production to five interstate pipeline delivery options.

In November 2010, the Company sold certain oil and gas properties in the Texas panhandle to Kimbrel Oil Corporation and Millbrae Energy VII, LLC for $11.5 million and recognized a $10.8 million gain on sale of assets.

In July 2010, the Company sold certain oil and gas properties located in Colorado to Patera Oil & Gas LLC for approximately $3.0 million. During the second quarter of 2010, the Company recognized an impairment loss of approximately $5.8 million associated with the sale of these properties. The impairment charge is included in Gain / (Loss) on Sale of Assets in the Consolidated Statement of Operations. Fair value of the impaired properties was determined using a market approach which considered the execution of a purchase and sale agreement the Company entered into on June 30, 2010. Accordingly, the inputs associated with the fair value of assets held for sale were considered Level 2 in the fair value hierarchy.

In June 2010, the Company sold its Woodford shale prospect located in Oklahoma to Continental Resources, Inc. The Company received approximately $15.9 million in cash proceeds and recognized a $10.3 million gain on sale of assets.

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The Company recognized a $3.3 million aggregate loss on sale of assets for the year ended December 31, 2009. This loss included a loss of approximately $16.0 million primarily related to the sale of the Canadian properties described below and a gain of $12.7 million primarily related to the sale of Thornwood properties in the North region. Cash proceeds of $11.4 million were received from the sale of the Thornwood properties.

In April 2009, the Company sold substantially all of its Canadian properties to a Tourmaline Oil Corporation (Tourmaline). Total consideration received from the sale was $84.4 million, consisting of $63.8 million in cash and $20.6 million in common stock of Tourmaline (see Note 4). The total net book value of the Canadian properties sold was $95.0 million. At December 31, 2008, the Company recorded 40.4 Bcfe of proved reserves (two percent of total proved reserves) related to these properties.

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3. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:

	December 31,
(In thousands)	2010			2009
ACCOUNTS RECEIVABLE, NET
Trade Accounts	$	91,077		$	78,656
Joint Interest Accounts		4,901			3,564
Other Accounts		2,603			1,756
		98,581			83,976
Allowance for Doubtful Accounts		(4,093	)		(3,614	)
	$	94,488		$	80,362
INVENTORIES
Natural Gas in Storage	$	13,371		$	14,434
Tubular Goods and Well Equipment		17,072			14,420
Pipeline Imbalances		(776	)		(864	)
	$	29,667		$	27,990
OTHER CURRENT ASSETS
Drilling Advances	$	2,796		$	3,417
Prepaid Balances		2,925			5,980
Deferred Income Taxes		257			—
	$	5,978		$	9,397
OTHER ASSETS
Rabbi Trust Deferred Compensation Plan	$	15,788		$	10,031
Debt Issuance Cost		22,061			11,621
Other Accounts		1,414			1,412
Investment in Equity Securities		—			20,636
	$	39,263		$	43,700
ACCOUNTS PAYABLE
Trade Accounts	$	27,401		$	17,434
Natural Gas Purchases		3,596			3,558
Royalty and Other Owners		36,034			40,080
Accrued Capital Costs		146,824			141,122
Taxes Other Than Income		2,655			4,267
Drilling Advances		523			864
Wellhead Gas Imbalances		5,142			4,140
Other Accounts		7,806			4,123
	$	229,981		$	215,588
ACCRUED LIABILITIES
Employee Benefits	$	10,790		$	11,222
Pension and Postretirement Benefits		1,688			1,469
Taxes Other Than Income		14,576			22,780
Interest Payable		19,488			20,205
Derivative Contracts		—			425
Other Accounts		1,355			1,948
	$	47,897		$	58,049
OTHER LIABILITIES
Rabbi Trust Deferred Compensation Plan	$	21,600		$	19,087
Derivative Contracts		2,180			1,954
Other Accounts		8,399			6,793
	$	32,179		$	27,834

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4. Investment in Equity Securities Carried at Cost

In April 2009, the Company received three million shares of common stock in Tourmaline as partial proceeds for the sale of substantially all of the Company’s Canadian assets. The common stock was carried at cost of $20.6 million and was included in Other Assets in the Consolidated Balance Sheet. As of December 31, 2009, the Company estimated the fair value of its investment to be $42.8 million based on the common stock value received in a recent private placement of Tourmaline’s common stock. Accordingly, the inputs associated with the fair value of the investment were considered level 3 in the fair value hierarchy.

In November 2010, the Company sold its investment in common stock of Tourmaline for $61.3 million and recognized a gain of $40.7 million which is included in Gain/(Loss) on Sale of Assets in the Consolidated Statement of Operations.

5. Debt and Credit Agreements

The Company’s debt consisted of the following as of:

(In thousands)	December 31, 2010		December 31, 2009
Long-Term Debt
7.33% Weighted-Average Fixed Rate Notes	$	95,000	$	170,000
6.51% Weighted-Average Fixed Rate Notes		425,000		425,000
9.78% Notes		67,000		67,000
5.58% Weighted-Average Fixed Rate Notes		175,000		—
Credit Facility		213,000		143,000
	$	975,000	$	805,000

The Company has debt maturities of $75 million due in 2013. No other tranches of debt are due within the next five years.

In June 2010, the Company amended the agreements governing its senior notes to amend the required asset coverage ratio (the present value of the Company’s proved reserves plus working capital to debt) contained in the agreements. The amendments revised the calculation of present value of proved reserves to reflect specified pricing assumptions based on quoted futures prices in lieu of historical realized prices, reduced the limit on proved undeveloped reserves included in the calculation from 35% to 30%, and increased the required ratio to 1.75:1 from 1.50:1. The amendments also provided that for so long as a borrowing base calculation is required under the Company’s credit facility, the calculated indebtedness may not exceed 115% of such borrowing base for this ratio. If such a borrowing base calculation is not required under the credit facility, the Company would no longer be subject to the asset coverage ratio under the agreements, but would instead be required to maintain a ratio of debt to consolidated EBITDAX (as defined) not to exceed 3.0 to 1.0. In conjunction with the amendments, the Company incurred $2.0 million of debt issuance costs which were capitalized and are being amortized over the term of the respective amended agreements in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

7.33% Weighted-Average Fixed Rate Notes

In July 2001, the Company issued $170 million of Notes to a group of seven institutional investors in a private placement. The Notes have bullet maturities and were issued in three separate tranches as follows:

	Principal		Term		Maturity Date		Coupon
Tranche 1	$	75,000,000		10-year		July 2011		7.26	%
Tranche 2	$	75,000,000		12-year		July 2013		7.36	%
Tranche 3	$	20,000,000		15-year		July 2016		7.46	%

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The 7.33% weighted-average fixed rate notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. Those covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) of at least 1.75 to 1.0 (as amended) and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

In December 2010, the Company repaid the $75.0 million outstanding of Tranche 1 prior to the due date. In connection with the early payment the Company was required to pay a make-whole premium of $2.8 million which is included in Interest Expense and Other in the Consolidated Statement of Operations.

6.51% Weighted-Average Fixed Rate Notes

In July 2008, the Company issued $425 million of senior unsecured fixed-rate notes to a group of 41 institutional investors in a private placement. The Notes have bullet maturities and were issued in three separate tranches as follows:

	Principal		Term		Maturity Date		Coupon
Tranche 1	$	245,000,000		10-year		July 2018		6.44	%
Tranche 2	$	100,000,000		12-year		July 2020		6.54	%
Tranche 3	$	80,000,000		15-year		July 2023		6.69	%

Interest on each series of the 6.51% weighted-average fixed rate notes is payable semi-annually. The Company may prepay all or any portion of the Notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The Notes contain restrictions on the merger of the Company with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. These covenants include a required asset coverage ratio (present value of proved reserves plus adjusted cash (as defined in the note purchase agreement) to debt and other liabilities) of at least 1.75 to 1.0 (as amended) and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. The Notes also are subject to customary events of default. The Company is required to offer to prepay the Notes upon specified change in control events accompanied by a ratings decline below investment grade.

9.78% Notes

In December 2008, the Company issued $67 million aggregate principal amount of its 10-year 9.78% Series G Senior Notes to a group of four institutional investors in a private placement. Interest on the Notes is payable semi-annually. The Company may prepay all or any portion of the Notes on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The other terms of the Notes are substantially similar to the terms of the 6.51% Weighted-Average Fixed Rate Notes.

5.58% Weighted-Average Fixed Rate Notes

In December 2010, the Company issued $175 million of senior unsecured fixed-rate notes to a group of eight institutional investors in a private placement. The Notes have bullet maturities and were issued in three separate tranches as follows:

	Principal		Term		Maturity Date		Coupon
Tranche 1	$	88,000,000		10-year		January 2021		5.42	%
Tranche 2	$	25,000,000		12-year		January 2023		5.59	%
Tranche 3	$	62,000,000		15-year		January 2026		5.80	%

Interest on each series of the 5.58% weighted-average fixed rate notes is payable semi-annually. The Company may prepay all or any portion of the Notes of each series on any date at a price equal to the principal

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amount thereof plus accrued and unpaid interest plus a make-whole premium. The other terms of the Notes are substantially similar to the terms of the 6.51% Weighted-Average Fixed Rate Notes.

Revolving Credit Agreement

In September 2010, the Company amended and restated its revolving credit facility. The credit facility provides for an available credit line of $900 million and contains an accordion feature allowing the Company to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. The credit facility also provides for the issuance of letters of credit, which would reduce the Company’s borrowing capacity. The amended facility provides for a $1.5 billion borrowing base and matures in September 2015.

In conjunction with entering into the September 2010 amended credit facility, the Company incurred $11.7 million of debt issuance costs, which were capitalized and will be amortized over the term of the amended credit facility. Approximately $6.3 million in unamortized costs associated with the original credit facility, as amended in June 2010, will be amortized over the term of the amended credit facility in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

The credit facility is unsecured. The available credit line is subject to adjustment from time to time on the basis of (1) the projected present value (as determined by the banks based on the Company’s reserve reports and engineering reports) of estimated future net cash flows from certain proved oil and gas reserves and certain other assets of the Company (the “Borrowing Base”) and (2) the outstanding principal balance of the Company’s senior notes. Under the credit facility, the Borrowing Base is set at $1.5 billion, to be periodically redetermined as described below. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings in connection with scheduled redetermination or due to a termination of hedge positions, the Company has a period of six months to reduce its outstanding debt in equal monthly installments to the adjusted credit line available.

The Borrowing Base is redetermined annually under the terms of the credit facility on April 1^st. In addition, either the Company or the banks may request an interim redetermination twice a year in connection with certain acquisitions or sales of oil and gas properties.

Interest rates under the credit facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin. These associated margins increase if the total indebtedness under the credit facility and the Company’s senior notes is greater than 25%, greater than 50%, greater than 75% or greater than 90% of the Borrowing Base, as shown below:

	Debt Percentage
	<25%			³ 25% <50%			³ 50% <75%			³ 75% <90%			³ 90%
Eurodollar Margin		2.000	%		2.250	%		2.500	%		2.750	%		3.000	%
Base Rate Margin		1.125	%		1.375	%		1.625	%		1.875	%		2.125	%

The credit facility provides for a commitment fee on the unused available balance at annual rates of 0.50%.

The credit facility contains various customary restrictions, which include the following (with all calculations based on definitions contained in the agreement):

(a) Maintenance of a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

(b) Maintenance of an asset coverage ratio of the present value of proved reserves plus working capital to debt of 1.75 to 1.0.

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(c) Maintenance of a current ratio of 1.0 to 1.0.

(d) Prohibition on the merger or sale of all or substantially all of the Company’s or any subsidiary’s assets to a third party, except under certain limited conditions.

In addition, the credit facility includes a customary condition to the Company’s borrowings under the facility that a material adverse change has not occurred with respect to the Company.

At December 31, 2010 and 2009, borrowings outstanding under the Company’s credit facilities were $213.0 million and $143.0 million, respectively. In addition, the Company had $0.30 million letters of credit outstanding at December 31, 2010.

The Company’s weighted-average effective interest rates for the credit facilities during the years ended December 31, 2010, 2009 and 2008 were approximately 3.8%, 4.0% and 4.8%, respectively. As of December 31, 2010 and 2009, the weighted-average interest rate on the Company’s credit facility was approximately 3.1% and 3.9%, respectively.

6. Employee Benefit Plans

Pension Plan

The Company has a non-contributory, defined benefit pension plan for all full-time employees, referred to as the tax qualified defined benefit pension plan (qualified pension plan). Plan benefits are based primarily on years of service and salary level near retirement. Plan assets are mainly equity securities and fixed income investments. The Company complies with the Employee Retirement Income Security Act (ERISA) of 1974 and Internal Revenue Code limitations when funding the plan.

The Company also has an unfunded non-qualified supplemental pension plan to ensure payments to certain executive officers of amounts to which they would have been entitled under the provisions of the pension plan, but for limitations imposed by federal tax laws, referred to as the supplemental non-qualified pension arrangements (non-qualified pension plan).

Termination and Amendment of Qualified and Non-Qualified Pension Plans

On July 28, 2010, the Company notified its employees of its plan to terminate its qualified pension plan, with the plan and its related trust to be liquidated following appropriate filings with the Pension Benefit Guaranty Corporation and Internal Revenue Service, effective September 30, 2010. The Company then amended and restated the qualified pension plan to freeze benefit accruals, to provide for termination of the plan, to allow for an early retirement enhancement to be available to all active participants as of September 30, 2010 regardless of their age and years of service as of that date, and to make certain changes that were required or made desirable as a result of developments in the law. Because no further benefits will accrue under the qualified pension plan after September 30, 2010, the Company’s related non-qualified pension plan was effectively frozen and no additional benefits will be accrued under those arrangements after September 30, 2010.

Freezing the above plans resulted in a remeasurement of the pension obligations and plan assets as of July 28, 2010. In calculating the remeasurement at the time of the termination, management used a discount rate of 5.25% for the qualified pension plan and 4.5% for the non-qualified pension plan, which was consistent with the Company’s methodology of determining the discount rate for these plans in prior periods. The discount rate was based on a yield curve based on high-quality corporate bonds that could be purchased to settle the pension obligation. Management determined the discount rate by matching this yield curve with the timing and amounts of the expected benefit payments for the Company’s plans.

As a result of these changes to the Company’s qualified and non-qualified pension plans, the Company revised its amortization period for prior service costs and actuarial losses, which are now amortized over 17

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months (from August 2010 to December 2011) to reflect the expected amortization period until final distribution of benefits from each plan. Prior service costs established in each plan prior to freeze were fully recognized in the third quarter of 2010 as a result of the plan freeze. Actuarial losses in the qualified pension plan were previously amortized over 10.6 years and actuarial losses in the non-qualified pension plan were previously amortized over 6 years.

Obligations and Funded Status

The funded status represents the difference between the projected benefit obligation of the Company’s qualified and non-qualified pension plans and the fair value of the qualified pension plan’s assets at December 31.

The change in the combined projected benefit obligation of the Company’s qualified and non-qualified pension plans and the change in the Company’s qualified pension plan assets at fair value during the last three years are as follows:

(In thousands)	2010			2009			2008
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	75,092		$	63,008		$	51,603
Service Cost		2,774			3,443			3,313
Interest Cost		3,700			3,712			3,272
Actuarial Loss		9,265			6,262			5,683
Plan Termination and Amendment		(12,331	)		—			—
Benefits Paid		(14,628	)		(1,333	)		(863	)
Benefit Obligation at End of Year		63,872			75,092			63,008
Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year		53,180			34,295			44,744
Actual Return on Plan Assets		7,095			10,903			(13,682	)
Employer Contributions		15,416			10,136			5,000
Benefits Paid		(14,628	)		(1,333	)		(863	)
Expenses Paid		(985	)		(821	)		(904	)
Fair Value of Plan Assets at End of Year		60,078			53,180			34,295
Funded Status at End of Year	$	(3,794	)	$	(21,912	)	$	(28,713	)

Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet at December 31 consist of the following:

(In thousands)	2010			2009			2008
Current Liabilities	$	(603	)	$	(488	)	$	(245	)
Long-Term Liabilities		(3,191	)		(21,424	)		(28,468	)
	$	(3,794	)	$	(21,912	)	$	(28,713	)

Amounts Recognized in Accumulated Other Comprehensive Income

Amounts recognized in accumulated other comprehensive income at December 31 consist of the following:

(In thousands)	2010		2009		2008
Prior Service Cost	$	1,267	$	92	$	143
Net Actuarial Loss		12,248		32,061		36,373
	$	13,515	$	32,153	$	36,516

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Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets

(In thousands)	2010		2009		2008
Projected Benefit Obligation	$	63,872	$	75,092	$	63,008
Accumulated Benefit Obligation	$	63,872	$	61,822	$	48,050
Fair Value of Plan Assets	$	60,078	$	53,180	$	34,295

Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income Combined Qualified and Non-Qualified Pension Plans

(In thousands)	2010			2009			2008
Components of Net Periodic Benefit Cost
Current Year Service Cost	$	2,774		$	3,443		$	3,313
Interest Cost		3,700			3,712			3,272
Expected Return on Plan Assets		(4,260	)		(2,685	)		(3,535	)
Amortization of Prior Service Cost		572			51			51
Amortization of Net Loss		8,705			3,177			1,175
Plan Termination and Amendment		4,444			—			—
Net Periodic Pension Cost	$	15,935		$	7,698		$	4,276
Other Changes in Qualified Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
Effect of Plan Termination and Amendment	$	(816	)	$	—		$	—
Settlement		(4,021	)		—			—
Net (Gain) / Loss		(4,523	)		(1,135	)		23,804
Amortization of Net Loss		(8,705	)		(3,335	)		(1,175	)
Amortization of Prior Service Cost		(572	)		—			(51	)
Total Recognized in Other Comprehensive Income	$	(18,637	)	$	(4,470	)	$	22,578
Total Recognized in Net Periodic Benefit Cost and Other Comprehensive Income	$	(2,702	)	$	3,228		$	26,854

The estimated prior service cost and net loss for the qualified pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $1.0 million and $10.9 million, respectively.

The estimated prior service cost and net loss for the defined benefit non-qualified pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $0.3 million and $1.3 million, respectively.

Assumptions

Weighted-average assumptions used to determine projected pension benefit obligations at December 31 were as follows:

	2010			2009			2008
Discount Rate		5.25	%		5.75	%		6.00	%
Rate of Compensation Increase		—			4.00	%		4.00	%

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Weighted-average assumptions used to determine net periodic pension costs at December 31 are as follows:

	2010			2009			2008
Discount Rate (January 1 - December 31)(1)		—			5.75	%		5.75	%
Discount Rate (January 1, 2010 - July 31, 2010)(2)		5.25	%		—			—
Discount Rate (August 1, 2010 - December 31, 2010)(2)		4.80	%		—			—
Expected Long-Term Return on Plan Assets		8.00	%		8.00	%		8.00	%
Rate of Compensation Increase		—			4.00	%		4.00	%

⁽¹⁾ Represents the discount rate used to determine the projected benefit costs for qualified and non-qualified pension plans for 2008 and 2009, respectively.

⁽²⁾ Represents the discount rate used to determine the net periodic pension costs for qualified and non-qualified pension plans for 2010. 5.25% was used from January 1, 2010 through July 31, 2010. Due to the plan termination and amendments that were effective in July 2010, the discount rate was adjusted for determining the net periodic pension costs for the remainder of the year to 4.8%.

The long-term expected rate of return on plan assets used in 2010, as shown above, is 8.0%. The Company establishes the long-term expected rate of return by developing a forward looking long-term expected rate of return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. One of the plan objectives is that performance of the equity portion of the pension plan exceeds the Standard and Poors’ 500 Index over the long-term. The Company also seeks to achieve a minimum five percent annual real rate of return (above the rate of inflation) on the total portfolio over the long-term. In the Company’s pension calculations, the Company has used 8.0 % as the expected long-term return on plan assets for 2010, 2009 and 2008. In order to derive this return, a Monte Carlo simulation was run using 5,000 simulations based upon the Company’s actual asset allocation and liability duration, which has been determined to be approximately 15 years. This model uses historical data for the period of 1926-2007 for stocks, bonds and cash to determine the best estimate range of future returns. The median rate of return, or return that the Company expects to achieve over 50% of the time, is approximately 9%. The Company expects to achieve at a minimum approximately 7% annual real rate of return on the total portfolio over the long-term at least 75% of the time. The Company believes that the 8% chosen is a reasonable estimate based on its actual results.

Plan Assets

The Company’s pension plan assets were accounted for at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Each portfolio uses independent pricing services approved by the Trustee to value the Company’s investments. All common/collective trust funds are managed by the Trustee. Refer to Note 14 for more information and a description of the fair value hierarchy.

The Company’s investments in equity securities for which market quotations are readily available are valued at the last reported sale price or official closing price as reported by an independent pricing service on the primary market or exchange on which they are traded.

The Company’s investment in debt securities are valued based on quotations received from dealers who transact in markets with such securities or by independent pricing services. For corporate bonds, bank notes, floating rate loans, foreign government and government agency obligations, municipal securities, preferred securities, supranational obligations, U.S. government and government agency obligations pricing services generally utilize matrix pricing which considers yield or price of bonds of comparable quality, coupon, maturity and type as well as dealer supplied prices.

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At December 31, 2010 and 2009, the non-qualified pension plan did not have plan assets. The fair value of the plan assets of the Company’s qualified pension plan at December 31, 2010 and 2009 by asset category are as follows:

(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2010
Asset Category
Cash	$	1,201	$	—	$	—	$	1,201
Equity securities:
Domestic:
Large-cap		—		17,578		—		17,578
Small-cap		—		3,072		—		3,072
Emerging Markets		—		1,817		—		1,817
Growth		—		3,623		—		3,623
International:
Diversified		—		10,204		—		10,204
Small-cap		—		1,232		—		1,232
Debt securities		—		21,351		—		21,351
	$	1,201	$	58,877	$	—	$	60,078

(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2009
Asset Category
Cash	$	1,486	$	—	$	—	$	1,486
Equity securities:
Domestic:
Large-cap		—		13,070		—		13,070
Small-cap		—		2,731		—		2,731
Growth		—		4,544		—		4,544
International:
Diversified		—		9,623		—		9,623
Small-cap		—		2,140		—		2,140
Debt securities		—		19,586		—		19,586
	$	1,486	$	51,694	$	—	$	53,180

The Company’s investment strategy for the pension benefit plan assets is to remain fully invested in the market until the final determination for the plan termination is complete. The Company will continue to target a portfolio of assets utilizing equity securities, debt securities and cash equivalents that are within a range of approximately 50% to 80% for equity securities and approximately 20% to 40% for fixed income securities.

Cash Flows

Employer Contributions

The funding levels of the pension and postretirement benefit plans (described below) are in compliance with standards set by applicable law or regulation. The Company did not have any required minimum funding obligations for its qualified pension plan in 2010; however, it chose to fund $10.0 million into the qualified pension plan. In 2011, the Company does not have any required minimum funding obligations for the qualified plan. Currently, management has not determined if any additional discretionary funding will be made in 2011.

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The Company previously disclosed in its financial statements for the year ended December 31, 2009 that it expected to contribute $0.5 million to its non-qualified pension plan in 2010. During 2010, the Company contributed $5.4 million to its non-qualified pension plan primarily due to settlements during the year.

Estimated Future Benefit Payments

As a result of the termination of the qualified and non-qualified pension plans, the Company expects to make a final distribution of benefits from each plan in late 2011 or early 2012.

Postretirement Benefits Other than Pensions

In addition to providing pension benefits, the Company provides certain health care benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. The health care plans are contributory, with participants’ contributions adjusted annually. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 257 retirees and their dependents at the end of 2010 and 251 retirees and their dependents at the end of 2009.

When the Company adopted ASC 715-60, “Compensation—Retirement Benefits—Defined Benefit Plans—Other Postretirement” in 1992, it began amortizing the $16.9 million accumulated postretirement benefit, known as the transition obligation, over a period of 20 years, or $0.8 million per year which is included in the annual expense of the plan. Included in the transition obligation are the effects of plan amendments during 1996, 2000 and 2004. As a result of subsequent updates to the requirements for accounting for Defined Benefit Plans codified in ASC 715-20, “Compensation—Retirement Benefits—Defined Benefit Plans—General,” the remaining unamortized balance at December 31, 2006 of $3.2 million is now recognized in accumulated other comprehensive income. Additionally, a portion of this amount will be amortized and reclassified from the balance sheet to the income statement as expense each year.

Obligations and Funded Status

The funded status represents the difference between the accumulated benefit obligation of the Company’s postretirement plan and the fair value of plan assets at December 31. The postretirement plan does not have any plan assets; therefore, the funded status is equal to the amount of the December 31 accumulated benefit obligation.

The change in the Company’s postretirement benefit obligation during the last three years, as well as the funded status at the end of the last three years is as follows:

(In thousands)	2010			2009			2008
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	34,392		$	26,888		$	20,846
Service Cost		1,265			1,279			1,083
Interest Cost		1,696			1,594			1,380
Actuarial Loss		(4,415	)		5,917			4,270
Benefits Paid		(991	)		(1,286	)		(691	)
Benefit Obligation at End of Year	$	31,947		$	34,392		$	26,888
Change in Plan Assets
Fair Value of Plan Assets at End of Year		N/A			N/A			N/A
Funded Status at End of Year	$	(31,947	)	$	(34,392	)	$	(26,888	)

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Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet at December 31 consist of the following:

(In thousands)	2010			2009			2008
Current Liabilities	$	(1,085	)	$	(981	)	$	(642	)
Long-Term Liabilities		(30,862	)		(33,411	)		(26,246	)
	$	(31,947	)	$	(34,392	)	$	(26,888	)

Amounts Recognized in Accumulated Other Comprehensive Income

Amounts recognized in accumulated other comprehensive income at December 31 consist of the following:

(In thousands)	2010		2009		2008
Transition Obligation	$	632	$	1,263	$	1,895
Prior Service Cost		—		—		666
Net Actuarial Loss		8,408		13,455		8,214
	$	9,040	$	14,718	$	10,775

The estimated net obligation at transition and net loss for the defined benefit postretirement plan that will be amortized from accumulated other comprehensive income into net periodic postretirement cost over the next fiscal year are $0.6 million and $0.6 million, respectively.

Components of Net Periodic Benefit Cost

(In thousands)	2010			2009			2008
Components of Net Periodic Postretirement Benefit Cost
Current Year Service Cost	$	1,265		$	1,279		$	1,083
Interest Cost		1,696			1,594			1,380
Amortization of Prior Service Cost		—			666			952
Amortization of Net Obligation at Transition		632			632			632
Amortization of Net Loss		631			676			448
Net Periodic Postretirement Cost	$	4,224		$	4,847		$	4,495
Other Changes in Benefit Obligations Recognized in Other Comprehensive Income
Net (Gain) / Loss	$	(4,415	)	$	5,917		$	4,270
Amortization of Prior Service Cost		—			(666	)		(952	)
Amortization of Net Obligation at Transition		(632	)		(632	)		(632	)
Amortization of Net Loss		(631	)		(676	)		(448	)
Total Recognized in Other Comprehensive Income		(5,678	)		3,943			2,238
Total Recognized in Qualified Net Periodic Benefit Cost and Other Comprehensive Income	$	(1,454	)	$	8,790		$	6,733

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Assumptions

Assumptions used to determine projected postretirement benefit obligations and postretirement costs are as follows:

	2010			2009			2008
Discount Rate(1)		5.75	%		5.75	%		5.75	%
Health Care Cost Trend Rate for Medical Benefits Assumed for Next Year		9.00	%		10.00	%		9.00	%
Rate to which the cost trend rate is assumed to decline (the Ultimate Trend Rate)		5.00	%		5.00	%		5.00	%
Year that the rate reaches the Ultimate Trend Rate		2015			2015			2013

⁽¹⁾ Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2010, 2009 and 2008, respectively, the beginning of year discount rates of 5.75%, 5.75% and 6.0% were used.

Coverage provided to participants age 65 and older is under a fully-insured arrangement. The Company subsidy is limited to 60% of the expected annual fully-insured premium for participants age 65 and older. For all participants under age 65, the Company subsidy for all retiree medical and prescription drug benefits, beginning January 1, 2006, was limited to an aggregate annual amount not to exceed $648,000. This limit increases by 3.5% annually thereafter. The Company prepaid the life insurance premiums for all retirees retiring before January 1, 2006 eliminating all future premiums for retiree life insurance. A life insurance product is offered to employees allowing employees to continue coverage into retirement by paying the premiums directly to the life insurance provider.

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

(In thousands)	1-Percentage- Point  Increase		1-Percentage- Point  Decrease
Effect on total of service and interest cost	$	516	$	(419	)
Effect on postretirement benefit obligation		4,727		(3,893	)

Cash Flows

Contributions

The Company expects to contribute approximately $1.1 million to the postretirement benefit plan in 2011.

Estimated Future Benefit Payments

The following estimated benefit payments under the Company’s postretirement plans, which reflect expected future service, as appropriate, are expected to be paid as follows:

(In thousands)
2011	$	1,116
2012		1,195
2013		1,384
2014		1,588
2015		1,717
Years 2016 - 2020		11,119

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit

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plans that provide a benefit that is at least actuarially equivalent to certain Medicare benefits. In accordance with accounting and disclosure requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 codified in ASC 715-60, any measures of the accumulated plan benefit obligation or net periodic postretirement benefit cost in the financial statements or accompanying notes do not reflect the effects of the Act on the Company’s plan. As amended by the Company on January 1, 2006, the postretirement benefit plan excludes prescription drug benefits to participants age 65 and older. Due to this amendment, there was no impact on operating results, financial position or cash flows of the Company.

Savings Investment Plan

The Company has a Savings Investment Plan (SIP), which is a defined contribution plan. The Company matches a portion of employees’ contributions in cash. Participation in the SIP is voluntary, and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $2.2 million, $2.2 million and $2.2 million in 2010, 2009 and 2008, respectively. The Company matches employee contributions dollar-for-dollar on the first six percent of an employee’s pretax earnings. The Company’s common stock is an investment option within the SIP.

In July 2010, the Company amended the SIP to provide for discretionary profit sharing contributions upon termination of the qualified pension plan effective September 30, 2010. The Company presently makes a discretionary profit-sharing contribution to this plan in an amount equal to 9% of an eligible plan participant’s salary and bonus. The Company charged to expense plan contributions of $0.8 million in 2010.

Deferred Compensation Plan

In 1998, the Company established a Deferred Compensation Plan which was available to officers of the Company and acts as a supplement to the SIP. The Internal Revenue Code does not cap the amount of compensation that may be taken into account for purposes of determining contributions to the Deferred Compensation Plan and does not impose limitations on the amount of contributions to the Deferred Compensation Plan. Effective October 1, 2010, the Company amended the Deferred Compensation Plan to broaden the group of eligible employees who participate in the plan beyond the officers of the Company. Under this amendment, the Company may designate any member of the Company’s management group as a participant in the Deferred Compensation Plan and may further designate whether such a participant is eligible to make deferral elections from their compensation. At the present time, the Company anticipates making such a contribution to the Deferred Compensation Plan on behalf of a participant in the event that Internal Revenue Code limitations cause a participant to receive less than the full Company matching contribution under the SIP. The Deferred Compensation Plan was also amended to provide that the Company would credit the accounts of participants who had entered into supplemental employee retirement plan agreements with the Company in an amount equal to which such participant would have been entitled under the terms of the supplemental employee retirement plan agreement in effect between the Company and the participant as of September 29, 2010, if the participant had terminated employment on September 30, 2010. This amendment also placed restrictions on the payment of these amounts in order to comply with Section 409A of the Internal Revenue Code.

The assets of the Deferred Compensation Plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company.

The participants direct the deemed investment of amounts credited to their accounts under the Deferred Compensation Plan. The trust assets are invested in either mutual funds that cover the investment spectrum from equity to money market, or may include holdings of the Company’s common stock, which is funded by the issuance of shares to the trust. The mutual funds are publicly traded and have market prices that are readily available. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets, excluding the Company’s common stock, was $15.8 million and $10.0 million at December 31, 2010 and 2009, respectively, and is included within Other Assets in the Consolidated

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Balance Sheet. Related liabilities, including the Company’s common stock, totaled $21.6 million and $19.1 million at December 31, 2010 and 2009, respectively, and are included within Other Liabilities in the Consolidated Balance Sheet. With the exception of the Company’s common stock, there is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets because the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants.

The Company’s common stock held in the rabbi trust is recorded at the market value on the date of deferral, which totaled $6.6 million and $8.2 million at December 31, 2010 and 2009, respectively and is included within Additional Paid-in Capital in Stockholders’ Equity in the Consolidated Balance Sheet. As of December 31, 2010, 174,318 shares of the Company’s stock representing vested performance share awards were deferred into the rabbi trust. During 2010, an increase to the rabbi trust deferred compensation liability of $2.5 million was recognized, representing an increase of $4.1 million related to an increase in the closing price of all shares from December 31, 2009 to December 31, 2010 offset by a reduction in the liability due to shares that were sold out of the rabbi trust totaling $1.6 million. The Company’s common stock issued to the trust is not considered outstanding for purposes of calculating basic earnings per share, but is considered a common stock equivalent in the calculation of diluted earnings per share.

The Company charged to expense plan contributions of $109,196 in 2010, $0 in 2009 and less than $20,000 in 2008.

7. Income Taxes

Income tax expense is summarized as follows:

	Year Ended December 31,
(In thousands)	2010		2009			2008
Current
Federal	$	29,879	$	(26,323	)	$	2,631
State		3,424		(545	)		30
Total		33,303		(26,868	)		2,661
Deferred
Federal		37,981		100,896			116,127
State		23,828		919			5,545
Total		61,809		101,815			121,672
Total Income Tax Expense	$	95,112	$	74,947		$	124,333

Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows:

	Year Ended December 31,
(Dollars in thousands)	2010			2009			2008
Statutory Federal Income Tax Rate		35	%		35	%		35	%
Computed “Expected” Federal Income Tax	$	69,475		$	78,153		$	117,468
State Income Tax, Net of Federal Income Tax Benefit		6,638			4,476			6,581
Deferred Tax Adjustment Related to Change in Overall State Tax Rate		18,973			(3,925	)		(1,453	)
Sale of Foreign Assets		—			(1,656	)		—
Other, Net		26			(2,101	)		1,737
Total Income Tax Expense	$	95,112		$	74,947		$	124,333

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The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets were as follows:

	Year Ended December 31,
(In thousands)	2010		2009
Deferred Tax Liabilities
Property, Plant and Equipment	$	925,397	$	765,811
Hedging Liabilities / Receivables		6,419		42,243
Prepaid Expenses and Other		6,654		1,635
Total		938,470		809,689
Deferred Tax Assets
Alternative Minimum Tax Credit		62,105		38,835
Net Operating Loss		95,102		31,111
Foreign Tax Credits		6,354		1,738
Pension and Other Post-Retirement Benefits		13,342		20,914
Items Accrued for Financial Reporting Purposes and Other		46,871		37,186
Total		223,774		129,784
Net Deferred Tax Liabilities	$	714,696	$	679,905

As of December 31, 2010, The Company had alternative minimum tax credit carryforwards of $62.1 million which do not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the alternative minimum tax in any such year. The Company also had net operating loss carryforwards of $288.5 million for state reporting purposes, the majority of which will expire between 2016 and 2030. It is expected that these deferred tax benefits will be utilized prior to their expiration.

Uncertain Tax Positions

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

	Year Ended December 31,
(In thousands)	2010			2009		2008
Unrecognized tax benefit balance at beginning of year	$	500		$	500	$	2,425
Additions based on tax provisions related to the current year		—			—		—
Additions for tax positions of prior years					—		—
Reductions for tax positions of prior years		(500	)		—		(1,925	)
Settlements		—			—		—
Unrecognized tax benefit balance at end of year	$	—		$	500	$	500

During 2010, unrecognized tax benefits were reduced by $0.5 million as a result of the completion of Internal Revenue Service (IRS) Joint Committee on Taxation review of the 2005-2008 tax years that were under audit by the IRS. This reduction did not materially affect the effective tax rate. During 2008, the Company executed a final settlement agreement with the IRS that reduced unrecognized tax benefits by $1.9 million. This reduction did not affect the effective tax rate.

As of December 31, 2010, the Company did not have any uncertain tax positions reported in the Consolidated Balance Sheet.

The Company files income tax returns in the U.S. federal jurisdiction, various states and Canada. The Company is no longer subject to examinations by state authorities before 2005. The Company is not currently under examination by the IRS.

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8. Commitments and Contingencies

Firm Gas Transportation Agreements

The Company has incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. These agreements provide firm transportation capacity rights on pipeline systems primarily in the North region. The remaining terms on these agreements range from less than one year to approximately 20 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability. The agreements that the Company previously had in place on pipeline systems in Canada were transferred in April 2009 to the buyer in connection with the sale of the Company’s Canadian properties (discussed in Note 2).

During 2010, the Company entered into new firm gas transportation arrangements with third-party pipelines to transport approximately 296 Mmcf/day in the North region. One of the new agreements commenced in the second quarter of 2010 and the remaining new agreements are expected to commence in 2011, which includes the 20 year transportation agreement entered into with Williams in December 2010 (discussed in to Note 2). These new agreements have terms of five to twenty years from the respective commencement dates. Future obligations under firm gas transportation agreements which commenced during 2010 are $78.4 million as of December 31, 2010.

Future obligations under firm gas transportation agreements as of December 31, 2010 are as follows:

(In thousands)
2011	$	32,504
2012		35,684
2013		28,356
2014		28,356
2015		28,356
Thereafter		332,363
	$	485,619

Drilling Rig Commitments

As of December 31, 2010, the Company does not have any outstanding drilling commitments with initial terms greater than one year.

Lease Commitments

The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. Rent expense under these arrangements totaled $18.3 million, $17.4 million and $14.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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Future minimum rental commitments under non-cancelable leases in effect at December 31, 2010 are as follows:

(In thousands)
2011		5,414
2012		5,133
2013		4,769
2014		4,211
2015		2,631
Thereafter		—
	$	22,158

Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of business. When deemed necessary, the Company establishes reserves for certain legal proceedings. All known liabilities are accrued based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Environmental Matters

On November 4, 2009, the Company and the Pennsylvania Department of Environmental Protection (PaDEP) entered into a single settlement agreement (Consent Order) covering a number of separate, unrelated environmental issues occurring in 2008 and 2009, including releases of drilling mud and other substances, record keeping violations at various wells and alleged natural gas contamination of 13 water wells in Susquehanna County, Pennsylvania. The Company paid an aggregate $120,000 civil penalty with respect to all the matters covered by the Consent Order, which were consolidated at the request of the PaDEP.

On April 15, 2010, the Company and PaDEP reached agreement on modifications to the Consent Order (First Modified Consent Order). In the First Modified Consent Order, PaDEP and the Company agreed that the Company will provide a permanent source of potable water to 14 households, most of which the Company has already been supplying with water. The Company agreed to plug and abandon three vertical wells in close proximity to two of the households and to bring into compliance a fourth well in the nine square mile area of concern in Susquehanna County. The Company agreed to complete these actions prior to any new well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of concern. The Company also agreed to postpone drilling of new wells in the area of concern until all obligations under the consent orders are fulfilled. In addition, the Company agreed to take certain other actions if requested by PaDEP, which could include the plugging and abandonment of up to 10 additional wells. Under the First Modified Consent Order, the Company paid a $240,000 civil penalty and agreed to pay an additional $30,000 per month until all obligations under the First Modified Consent Order are satisfied.

On July 19, 2010, the Company and the PaDEP entered a Second Modification to Consent Order (Second Modified Consent Order) under which the Company and the PaDEP agreed that the Company has satisfactorily plugged and abandoned the three vertical wells and brought the fourth well into compliance. As a result, the Company and the PaDEP agreed that the PaDEP will commence the processing and issuance of new well drilling permits outside the area of concern so long as the Company continues to provide temporary potable water and offers to provide gas/water separators to the 14 households. No penalties were assessed under the Second Modified Consent Order.

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As required by the Second Modified Consent Order, the Company made offers to provide whole-house water treatment systems to the 14 households. As required by the First Modified Consent Order, on August 5, 2010 the Company filed with the PaDEP its report, prepared by its experts, finding that the Company’s well drilling and development activities are not the source of methane gas reported to be in the groundwater and water wells in the area of concern.

Despite the Company’s vigorous efforts to comply with the various consent orders, in a September 14, 2010 letter to the Company, the PaDEP rejected the Company’s expert report and determined that the Company’s drilling activities continue to cause the unpermitted discharge of natural gas into the groundwater and continue to affect residential water supplies in the area of concern. The PaDEP directed the Company, in accordance with the First Modified Consent Order, to plug or take other remedial actions at the remaining 10 wells and to contact the PaDEP to discuss connecting the impacted water supplies into a community public water system to permanently eliminate the continuing adverse affect to those water supplies.

The Company believed that it was in full compliance with the various consent orders. In a September 28, 2010 reply letter to the PaDEP, the Company disagreed with the PaDEP’s rejection of the Company’s expert report, disagreed that the remaining 10 wells continue to impact groundwater and affect residential water supplies and disagreed that a community public water system is necessary or feasible. It was the Company’s position that offering installation of a whole-house water treatment system to the 14 households constituted compliance with the Company’s obligations under these consent orders.

On December 15, 2010, the Company entered a global settlement agreement and new consent order with the PaDEP (Global Settlement Agreement), which supersedes the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. Under the Global Settlement Agreement, among other things, the Company agreed to pay $4.2 million into separate escrow accounts for the benefit of each affected household, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, remediate two wells in the affected area, provide pressure, water quality and well headspace data to the PaDEP and offer water treatment to the affected households. The Global Settlement Agreement settles all outstanding issues and claims that are known and that could have been brought against the Company by the PaDEP relating to the wells in the affected area and the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. It also allows the Company to begin hydraulic fracturing in the affected areas after providing the PaDEP with well pressure data and to commence drilling new wells in the affected area in the second quarter of 2011. Under the Global Settlement Agreement, the Company has no obligation to connect the impacted water supplies to a community public water system.

On January 11, 2011, certain of the affected households appealed the Global Settlement Agreement to the Pennsylvania Environmental Hearing Board. A hearing on the merits of this appeal is not expected to occur until 2012.

As of December 31, 2010, the Company has paid $1.3 million in fines and penalties to the PaDEP paid $0.6 million to two of the affected households and accrued a $3.6 million settlement liability related to this matter which is included in Other Liabilities in the Consolidated Balance Sheet.

Settlement of Dispute

In December 2008, the Company settled a dispute with a third party resulting in the Company recording a gain of $51.9 million. The dispute involved the propriety of possession of the Company’s intellectual property by a third party. The settlement was comprised of $20.2 million in cash paid by the third party to the Company and $31.7 million related to the fair value of unproved property rights transferred by the third party to the Company. The fair market value of the unproved property rights was determined based on observable market costs and conditions over a recent time period. Values were pro-rated by property based on the primary term remaining on the properties.

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9. Asset Retirement Obligation

The following table provides a rollforward of the asset retirement obligation. Liabilities settled include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Liabilities incurred include additions to obligations as well as obligations that were assumed by the Company related to acquired properties. Activity related to the Company’s asset retirement obligation during the year ended December 31, 2010 is as follows:

(In thousands)
Carrying amount of asset retirement obligation at December 31, 2009	$	29,676
Change in estimate		40,443
Liabilities incurred		966
Liabilities settled		(693	)
Accretion expense		1,919
Carrying amount of asset retirement obligation at December 31, 2010	$	72,311

The change in estimate during 2010 is attributable to additional regulatory requirements in east Texas and increased costs for services and equipment to plug and abandon wells in all of our areas of operations.

Accretion expense for the years ended December 31, 2010, 2009 and 2008 was $1.9 million, $1.3 million and $1.2 million, respectively.

10. Supplemental Cash Flow Information

Cash paid / (received) for interest and income taxes is as follows:

	Year Ended December 31,
(In thousands)	2010			2009		2008
Interest	$	64,342		$	56,301	$	23,089
Income Taxes		(1,050	)		27,080		(33,753	)

11. Capital Stock

Incentive Plans

Under the Company’s 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards. In the first quarter of 2007, the Board of Directors eliminated the automatic award of an option to purchase 30,000 shares of common stock on the date the non-employee directors first join the Board of Directors. In its place, the Board of Directors considers an annual fixed dollar stock award which is competitive with the Company’s peer group. A total of 5,100,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than 1,800,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 3,000,000 shares may be issued pursuant to incentive stock options.

Stock Issuance

On June 20, 2008, the Company entered into an underwriting agreement, pursuant to which the Company sold an aggregate of 5,002,500 shares of common stock at a price to the Company of $62.66 per share. On June 25, 2008, the Company closed the public offering and received $313.5 million in net proceeds, after deducting underwriting discounts and commissions. These net proceeds were used to reduce outstanding

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borrowings under the Company’s revolving credit facility prior to funding a portion of the purchase price of the Company’s east Texas acquisition, which closed in the third quarter of 2008.

Immediately prior to (and in connection with) this issuance, the Company retired 5,002,500 shares of its treasury stock, which had a weighted-average purchase price of $16.46, representing $82.3 million. In accordance with the Company’s policy, the excess of cost of the treasury stock over its par value was charged entirely to additional paid-in capital.

Increase in Authorized Shares

In April 2009, the stockholders of the Company approved an increase in the authorized number of shares of common stock from 120 million to 240 million shares.

Treasury Stock

The Board of Directors has authorized a share repurchase program under which the Company may purchase shares of common stock in the open market or in negotiated transactions. The timing and amount of these stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase securities of the Company.

During the year ended December 31, 2010, the Company did not repurchase any shares of common stock. Since the authorization date, the Company has repurchased 5,204,700 shares of the 10 million total shares authorized for a total cost of approximately $85.7 million. The repurchased shares were held as treasury stock. No treasury shares have been delivered or sold by the Company subsequent to the repurchase. In connection with the June 2008 common stock issuance, the Company retired 5,002,500 shares of its treasury stock as discussed above under the heading “Stock Issuance.” As of December 31, 2010, 202,200 shares were held as treasury stock.

Dividend Restrictions

The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the common stock depending on, among other things, the Company’s financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. None of the note or credit agreements in place have a restricted payment provision or other provision limiting dividends.

Expired Purchase Rights Plan

On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of common stock. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. At December 31, 2010 and 2009 there were no shares of Junior Preferred Stock issued or outstanding. The rights plan expired on January 21, 2010.

12. Stock-Based Compensation

Compensation expense charged against income for stock-based awards (including the supplemental employee incentive plan) for the years ended December 31, 2010, 2009 and 2008 was $14.4 million, $25.1 million and $34.5 million, respectively, and is included in General and Administrative Expense in the Consolidated Statement of Operations.

The Company did not recognize a tax benefit related to stock-based compensation in 2010 as a result of the tax net operating loss position for the year. For the year ended December 31, 2009, the Company realized a $13.8

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million tax benefit related primarily to the federal tax deduction in excess of book compensation cost for employee stock-based compensation for 2008 and, to a lesser extent, state tax deductions for 2007. For regular federal income tax purposes, the Company was in a net operating loss position in 2008. As the Company carried back net operating losses concurrent with its 2008 tax return filing, the income tax benefit related to stock-based compensation was recorded in 2009. In accordance with ASC 718, the Company is able to recognize this tax benefit only to the extent it reduces the Company’s income taxes payable. For the year ended December 31, 2008, the Company realized a $10.7 million tax benefit related to the 2007 federal tax deduction in excess of book compensation cost related to employee stock-based compensation. Such income tax benefit related to the stock-based compensation was recorded in 2008 as the Company carried back net operating losses concurrent with the 2007 tax return filing. The Company did not recognize a tax benefit related to stock-based compensation in 2007 as a result of the tax net operating loss position for the year. Under ASC 718, the tax benefits resulting from tax deductions in excess of expense are reported as an operating cash outflow and a financing cash inflow. For the years ended December 31, 2010, 2009 and 2008, $0.1 million, $13.8 million and $10.7 million were reported in these two separate line items in the Consolidated Statement of Cash Flows.

Restricted Stock Awards

Most restricted stock awards vest either at the end of a three year service period or on a graded-vesting basis at each anniversary date over a three or four year service period. For awards that vest at the end of the three year service period, expense is recognized ratably using a straight-line expensing approach over three years. Under the graded-vesting approach, the Company recognizes compensation cost ratably over the three or four year requisite service period, as applicable, for each separately vesting tranche as though the awards are, in substance, multiple awards. For all restricted stock awards, vesting is dependent upon the employees’ continued service with the Company, with the exception of employment termination due to death, disability or retirement.

The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is four years. In accordance with ASC 718, the Company accelerated the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company’s stock-based compensation programs for awards issued after the adoption of ASC 718. The Company used an annual forfeiture rate ranging from 0% to 7.0% based on approximately ten years of the Company’s history for this type of award to various employee groups.

The following table is a summary of restricted stock award activity for the year ended December 31, 2010:

Restricted Stock Awards	Shares			Weighted- Average Grant Date Fair Value per Share		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands)(1)
Outstanding at December 31, 2009		185,923		$	34.62
Granted		23,800			34.87
Vested		(46,350	)		32.61
Forfeited		(31,210	)		33.93
Non-vested shares outstanding at December 31, 2010		132,163		$	35.53		1.7	$	5,002

⁽¹⁾ The aggregate intrinsic value of restricted stock awards is calculated by multiplying the closing market price of the Company’s stock on December 31, 2010 by the number of non-vested restricted stock awards outstanding.

As shown in the table above, there were 23,800 shares of restricted stock granted to employees during 2010 with a weighted-average grant date fair value per share of $34.87. During the year ended December 31, 2009, 145,060 shares of restricted stock granted to employees with a weighted-average grant date fair value per share of $34.95. During the year ended December 31, 2008, 13,000 shares of restricted stock were granted to

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employees with a weighted-average grant date fair value per share of $40.93. The total fair value of shares vested during 2010, 2009 and 2008 was $1.5 million, $1.2 million and $6.5 million, respectively.

Compensation expense recorded for all restricted stock awards for the years ended December 31, 2010, 2009 and 2008 was $1.8 million, $1.2 million and $1.5 million, respectively. Included in 2010 restricted stock expense was $1.1 million related to the immediate expensing of shares granted to retirement-eligible employees. Unamortized expense as of December 31, 2010 for all outstanding restricted stock awards was $2.1 million and will be recognized over the next 1.8 years.

Restricted Stock Units

Restricted stock units are granted from time to time to non-employee directors of the Company. The fair value of these units is measured at the average of the high and low stock price on grant date and compensation expense is recorded immediately. These units immediately vest and are issued when the director ceases to be a director of the Company.

The following table is a summary of restricted stock unit activity for the year ended December 31, 2010:

Restricted Stock Units	Units		Weighted- Average Grant Date Fair Value per Unit		Weighted- Average Remaining Contractual Term (in years)(2)		Aggregate Intrinsic Value (in thousands)(1)
Outstanding at December 31, 2009		115,165	$	26.86
Granted and fully vested		26,961		40.07
Issued		—		—
Forfeited		—		—
Outstanding at December 31, 2010		142,126	$	29.37		—	$	5,379

⁽¹⁾ The intrinsic value of restricted stock units is calculated by multiplying the closing market price of the Company’s stock on December 31, 2010 by the number of outstanding restricted stock units.

⁽²⁾ Due to the immediate vesting of the units and the unknown term of each director, the weighted-average remaining contractual term in years has been omitted from the table below.

As shown in the table above, 26,961 restricted stock units were granted with a weighted-average grant date fair value per share of $40.07 during 2010. During 2009, 33,150 restricted stock units were granted with a weighted-average grant date fair value per share of $22.63. During 2008, 16,565 restricted stock units were granted with a weighted-average grant date fair value per share of $49.17.

The compensation cost, which reflects the total fair value of these units, recorded in 2010 was $1.1 million. Compensation expense recorded during the years ended December 31, 2009 and 2008 for restricted stock units was $0.8 million and $0.8 million, respectively.

Stock Options

Stock option awards are granted with an exercise price equal to the average of the high and low trading price of the Company’s stock at the date of grant. During the years ended December 31, 2010, 2009 and 2008, there were no stock options granted.

The Company uses a Black-Scholes model to calculate the fair value of stock options. Compensation cost is recorded based on a graded-vesting schedule as the options vest over a service period of three years, with

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one-third of the award becoming exercisable each year on the anniversary date of the grant. Stock options have a maximum contractual term of five years. No forfeiture rate is assumed for stock options granted to directors due to the forfeiture rate history for these types of awards for this group of individuals. During 2010 there was no compensation expense recorded. Compensation expense recorded for stock options for 2009 was less than $0.1 million and for 2008 was $0.1 million. There was no unamortized expense as of December 31, 2010 for stock options.

The following table is a summary of stock option activity for the years ended December 31, 2010, 2009 and 2008:

	2010					2009					2008
Stock Options	Shares			Weighted- Average Exercise Price		Shares			Weighted- Average Exercise Price		Shares			Weighted- Average Exercise Price
Outstanding at Beginning of Year		50,000		$	23.80		60,500		$	21.69		388,950		$	10.38
Granted		—					—			—		—			—
Exercised		(35,000	)		23.80		(10,500	)		11.66		(328,450	)		8.30
Forfeited or Expired		—			—		—			—		—			—
Outstanding at December 31(1)		15,000		$	23.80		50,000		$	23.80		60,500		$	21.69
Options Exercisable at December 31(2)		15,000		$	23.80		50,000		$	23.80		40,500		$	20.65

⁽¹⁾ The intrinsic value of a stock option is the amount which the current market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of options outstanding at December 31, 2010 was $0.2 million. The weighted-average remaining contractual term is less than one year.

⁽²⁾ The aggregate intrinsic value of options exercisable at December 31, 2010 was $0.2 million. The weighted-average remaining contractual term is less than one year.

The total intrinsic value of options exercised during the years ended December 31, 2010, 2009 and 2008 was less than $0.5 million, $0.1 million and $12.2 million, respectively.

Stock Appreciation Rights

Beginning in 2006, the Compensation Committee has granted SARs to employees. These awards allow the employee to receive any intrinsic value over the grant date market price that may result from the price appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and will vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. The Company calculates the fair value using a Black-Scholes model.

The assumptions used in the Black-Scholes fair value calculation on the date of grant for SARs are as follows:

	Year Ended December 31,
	2010			2009			2008
Weighted-Average Value per Stock Appreciation Rights
Granted During the Period	$	18.96		$	9.35		$	15.18
Assumptions
Stock Price Volatility		52.9	%		50.5	%		34.4	%
Risk Free Rate of Return		2.4	%		1.7	%		2.8	%
Expected Dividend Yield		0.3	%		0.5	%		0.2	%
Expected Term (in years)		5.0			4.5			4.3

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The expected term was derived by reviewing minimum and maximum expected term outputs from the Black-Scholes model based on award type and employee type. This term represents the period of time that awards granted are expected to be outstanding. The stock price volatility was calculated using historical closing stock price data for the Company for the period associated with the expected term through the grant date of each award. The risk free rate of return percentages are based on the continuously compounded equivalent of the U.S. Treasury (Nominal 10) within the expected term as measured on the grant date. The expected dividend percentage assumes that the Company will continue to pay a consistent level of dividend each quarter.

The following table is a summary of SAR activity for the years ended December 31, 2010, 2009 and 2008:

	2010					2009					2008
Stock Appreciation Rights	Shares			Weighted- Average Exercise Price		Shares			Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price
Outstanding at Beginning of Year		673,100		$	29.27		491,930		$	32.26		372,800	$	27.08
Granted		79,550			40.53		221,780			22.63		119,130		48.48
Exercised		(17,000	)		27.16		(20,366	)		26.19		—		—
Forfeited or Expired		—					(20,244	)		32.19		—
Outstanding at December 31(1)		735,650		$	30.54		673,100		$	29.27		491,930	$	32.26
Exercisable at December 31(2)		532,222		$	29.63		354,252		$	28.58		212,790	$	25.72

⁽¹⁾ The intrinsic value of a SAR is the amount which the current market value of the underlying stock exceeds the exercise price of the SAR. The aggregate intrinsic value of SARs outstanding at December 31, 2010 was $6.8 million. The weighted-average remaining contractual term is 3.5 years.

⁽²⁾ The aggregate intrinsic value of SARs exercisable at December 31, 2010 was $5.3 million. The weighted-average remaining contractual term is 2.8 years.

As shown in the table above, the Compensation Committee granted 79,550 SARs to employees during 2010 with a weighted-average exercise price equal to the grant date market price of $40.53. Compensation expense recorded during the years ended December 31, 2010, 2009 and 2008 for all outstanding SARs was $1.6 million, $1.8 million and $1.7 million, respectively. In 2010, there was no expense related to the immediate expensing of shares granted to retirement-eligible employees. Included in 2009 and 2008 expense was $0.7 million and $0.5 million, respectively, related to the immediate expensing of shares granted to retirement-eligible employees. Unamortized expense as of December 31, 2010 for all outstanding SARs was $0.6 million. The weighted-average period over which this compensation will be recognized is approximately 1.1 years.

Performance Share Awards

During 2010, the Compensation Committee granted three types of performance share awards to employees for a total of 347,170 performance shares. For all performance share awards granted to employees in 2010, an annual forfeiture rate ranging from 0% to 7.0% has been assumed based on the Company’s history for this type of award to various employee groups.

Awards totaling 180,180 performance shares based on performance conditions are earned, or not earned, based on the Company’s internal performance metrics. Fair value is measured based on the average of the high and low stock price of the Company on the grant date and expense is amortized straight-line over the three year period. The grant date per share value of this award was $40.53. These awards represent the right to receive up to 100% of the award in shares of common stock. The actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three internal performance criteria set by the Company’s Compensation Committee. The performance period for the awards granted in 2010 commenced

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on January 1, 2010 and ends December 31, 2012. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria measure the Company’s average production, average finding costs and average reserve replacement over three years. Based on the Company’s probability assessment at December 31, 2010, it is considered probable that these three criteria will be met for all outstanding awards.

The second type of performance share award, totaling 82,520 performance shares based on performance conditions, with a grant date per share value of $40.53, has a three-year graded performance period. Fair value is measured based on the average of the high and low stock price of the Company on the grant date and expense is amortized straight-line over the three year period. On each anniversary date following the date of grant, one-third of the shares are issued, provided that the Company has $100 million or more of operating cash flow for the year preceding the performance period. If the Company does not have $100 million or more of operating cash flow for the year preceding a performance period, then the portion of the performance shares that would have been issued on that date will be forfeited. As of December 31, 2010, it is considered probable that this performance metric will be met.

Awards totaling 84,470 performance shares based on market conditions are earned, or not earned, based on the comparative performance of the Company’s common stock measured against sixteen other companies in the Company’s peer group over a three year performance period. The performance period for the awards granted in 2010 commenced on January 1, 2010 and ends December 31, 2012. To determine the fair value for awards that are based on the Company’s comparative performance against a peer group (market condition), the equity and liability components are bifurcated. On the grant date, the equity component was valued using a Monte Carlo binomial model and is amortized on a straight-line basis over three years. The liability component is valued at each reporting period by using a Monte Carlo binomial model. Depending on the Company’s performance, employees may receive an aggregate of up to 100% of the fair market value of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash.

The four primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns, correlation in movement of total shareholder return and the expected dividend. An interpolated risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for two and three year bonds (as of the reporting date) set equal to the remaining duration of the performance period. Volatility was set equal to the annualized daily volatility for the remaining duration of the performance period ending on the reporting date. Correlation in movement of total shareholder return was determined based on a correlation matrix that was created which identifies total shareholder return correlations for each pair of companies in the peer group, including the Company. The paired returns in the correlation matrix ranged from approximately 60.48% to approximately 85.65% for the Company and its peer group. The expected dividend is calculated using the total Company annual dividends expected to be paid divided by the closing price of the Company’s stock at the valuation date. Based on these inputs discussed above, a ranking was projected identifying the Company’s rank relative to the peer group for each award period.

The following assumptions were used for the Monte Carlo model to determine the grant date fair value of the equity component of the performance share awards based on market conditions for the respective periods:

	Year Ended December 31,
	2010			2009			2008
Weighted-Average Fair Value per Performance Share
Award Granted During the Period	$	13.00		$	17.63		$	41.53
Assumptions
Stock Price Volatility		61.8	%		57.6	%		37.7	%
Risk Free Rate of Return		1.4	%		1.3	%		1.7	%
Expected Dividend Yield		0.3	%		0.5	%		0.2	%

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The following assumptions were used in the Monte Carlo model to determine the fair value of the liability component of the performance share awards based on market conditions for the respective periods:

	December 31,
	2010		2009
Fair Value per Performance Share Award at the End of the Period	$	0.00 - $6.15	$	14.38 - 16.24
Assumptions
Stock Price Volatility		70.7% - 71.7%		57.7% - 70.8%
Risk Free Rate of Return		0.3% - 0.4%		0.5% - 1.4%
Expected Dividend Yield		0.4%		0.3%

The long-term liability for market condition performance share awards, included in Other Liabilities in the Consolidated Balance Sheet, at December 31, 2010 and 2009 was $0.6 million and $1.1 million, respectively. The short-term liability, included in Accrued Liabilities in the Consolidated Balance Sheet, at December 31, 2010 and 2009 was 2.4 million for both periods.

On December 31, 2010, the performance period ended for two types of performance shares awarded in 2008, including 143,800 shares measured based on internal performance metrics of the Company and 96,680 shares measured based on the Company’s performance against a peer group. For the internal performance metric awards, the calculation of the average of the three years of the Company’s three internal performance metrics was completed in the first quarter of 2011 and was certified by the Compensation Committee in February 2011. As the Company achieved the three internal performance metrics, 100% of the award, valued at $6.9 million based on the average of the high and low stock price on the grant date, was payable in 143,800 shares of common stock. For the peer group awards, due to the ranking of the Company compared to its peers in its predetermined peer group, 75% of the award, valued at $3.0 million based on the Monte Carlo value on the grant date, was payable in 72,512 shares of common stock. The vesting of both types of shares discussed above will be reported in the first quarter of 2011.

The following table is a summary of performance share award activity for the year ended December 31, 2010:

Performance Share Awards	Shares			Weighted- Average Grant Date Fair Value per Share(1)		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands)(2)
Outstanding at December 31, 2009		1,296,393		$	29.74
Granted		347,170			38.48
Issued and Fully Vested		(410,269	)		32.28
Forfeited		(40,180	)		32.82
Outstanding at December 31, 2010		1,193,114		$	31.31		1.0	$	45,159

⁽¹⁾ The fair value figures in this table represent the fair value of the equity component of the performance share awards.

⁽²⁾ The aggregate intrinsic value of performance share awards is calculated by multiplying the closing market price of the Company’s stock on December 31, 2010 by the number of non-vested performance share awards outstanding.

Of the performance shares that vested during 2010 shown in the table above, 92,400 shares were granted in 2007. These shares (valued at $2.8 million) were measured based on the Company’s performance against a peer group and were issued in addition to cash of $1.3 million. A total of 150,100 shares (valued at $5.3 million) measured based on internal performance metrics of the Company were also issued. During 2010, 167,769

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shares vested (valued at $5.1 million) which represents one-third of the three-year graded vesting schedule performance share awards granted in 2009, 2008 and 2007 with a grant date per share value of $22.63, $48.48 and $35.22, respectively.

During the year ended December 31, 2009, 785,350 performance share awards were granted to employees with a weighted-average grant date fair value per share of $21.30. Of the 332,642 performance shares that vested during 2009, 105,800 shares were granted in 2006. These shares (valued at $1.7 million) were measured based on the Company’s performance against a peer group and were issued in addition to cash of $1.8 million. A total of 155,800 shares (valued at $3.8 million) measured based on internal performance metrics of the Company were also issued. During 2009, 60,740 shares vested (valued at $2.5 million) which represents one-third of the three-year graded vesting schedule performance share awards granted in 2008 and 2007 with a grant date per share value of $48.48 and $35.22, respectively. In addition, 10,302 performance shares vested as a result of early vesting schedules for certain employees. These awards met the performance criteria that the Company had positive operating income for 2008 and 2007.

During the year ended December 31, 2008, 383,065 performance share awards were granted with a weighted-average grant date fair value per share of $46.63. Of the 249,990 performance shares that vested during 2008, 207,800 shares were granted in 2005 and were market condition awards which provided that employees may receive an aggregate of up to 100% of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash. As a result of the Company’s ranking on the vesting date, 100% of the shares were paid in common stock and an additional 67% of the fair market value of each share of common stock, or $7.9 million, was paid in cash during the second quarter of 2008. Another 30,790 shares vested during 2008 and represent one-third of the three-year graded vesting schedule performance share awards granted in 2007 with a grant date per share value of $35.22. These awards met the performance criteria that the Company had positive operating income for the 2007 year. The remaining 11,400 shares vested as a result of the death of an employee of the Company.

During 2010, 2009 and 2008, 40,180, 120,090 and 37,000 performance shares, respectively, were forfeited.

Total unamortized compensation cost related to the equity component of performance shares at December 31, 2010 was $11.5 million and will be recognized over the next 1.9 years, computed by using the weighted-average of the time in years remaining to recognize unamortized expense. Total compensation cost recognized for both the equity and liability components of all performance share awards during the years ended December 31, 2010, 2009 and 2008 was $12.4 million, $15.6 million and $17.5 million, respectively.

Deferred Performance Shares

As of December 31, 2010, 174,318 shares of the Company’s common stock representing vested performance share awards were deferred into the Rabbi Trust Deferred Compensation Plan. A total of 51,482 shares were sold out of the plan in 2010. During 2010, an increase to the rabbi trust deferred compensation liability of $2.5 million was recognized, representing the increase in the investment excluding the Company’s common stock, offset by the decrease in the closing price of the Company’s common stock from December 31, 2009 to December 31, 2010 and the reduction in the liability due to shares that were sold out of the rabbi trust. This increase in stock-based compensation expense was included in General and Administrative expense in the Consolidated Statement of Operations.

Supplemental Employee Incentive Plans

On January 16, 2008, the Company’s Board of Directors adopted a Supplemental Employee Incentive Plan. The plan was intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time non-officer employees by providing for cash payments in the event the Company’s common stock reaches a specified trading price.

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The bonus payout was triggered if, for any 20 trading days (which need not be consecutive) that fell within a period of 60 consecutive trading days occurring on or before November 1, 2011, the closing price per share of the Company’s common stock equaled or exceeded the price goal of $60 per share. In such event, the 20th trading day on which such price condition was attained is the “Final Trigger Date.” Under the plan, each eligible employee would receive a minimum distribution of 50% of his or her base salary as of the Final Trigger Date, as adjusted for persons hired after December 31, 2007 to reflect calendar quarters of service, reduced by any interim distribution previously paid to such employee upon the achievement of the interim price goal discussed below. The Committee was authorized, in its discretion, to allocate to eligible employees additional distributions, subject to limitations of the plan.

The plan also provided that an interim distribution would be paid to eligible employees upon achieving the interim price goal of $50 per share prior to December 31, 2009. Interim distributions were determined as described above except that interim distributions were based on 10%, rather than 50%, of salary.

On the January 16, 2008 adoption date of the plan, the Company’s closing stock price was $40.71. On April 8, 2008 and subsequently on June 2, 2008, the Company achieved the interim and final target goals and total distributions of $15.7 million were paid in 2009. No further distributions will be made under this plan.

On July 24, 2008, the Company’s Board of Directors adopted a second Supplemental Employee Incentive Plan (“Plan II”). Plan II is also intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time non-officer employees by providing for cash payments in the event the Company’s common stock reaches a specified trading price.

Plan II provides for a final payout if, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days ending on or before June 20, 2012, the closing price per share of the Company’s common stock equals or exceeds the price goal of $105 per share. In such event, the 20th trading day on which such price condition is attained is the “Final Trigger Date.” The price goal is subject to adjustment by the Compensation Committee to reflect any stock splits, stock dividends or extraordinary cash distributions to stockholders. Under Plan II, each eligible employee may receive (upon approval by the Compensation Committee) a distribution of 50% of his or her base salary as of the Final Trigger Date (or 30% of base salary if the Company paid interim distributions upon the achievement of the interim price goal discussed below).

Plan II provides that a distribution of 20% of an eligible employee’s base salary as of the Interim Trigger Date will be made (upon approval by the Compensation Committee) upon achieving the interim price goal of $85 per share on or before June 30, 2010. The Company did not meet this interim trigger and therefore no distribution was made as of the Interim Trigger Date.

Payments under the final distribution will occur as follows:

• 25% of the total distribution paid on the 15^th business day following the final trigger date; and

• 75% of the total distribution paid based on the following deferred payment dates in the table below:

Period During which the Trigger Date Occurs	Deferred Payment Date
July 1, 2008 to June 30, 2009	The business day on or next following the 18 month anniversary of the applicable Trigger Date
July 1, 2009 to June 30, 2010	The business day on or next following the 12 month anniversary of the applicable Trigger Date
July 1, 2010 to December 31, 2010	The business day on or next following the 6 month anniversary of the applicable Trigger Date
January 1, 2011 to June 30, 2012	No deferral; entire payment is made on the 15th business day following the applicable Trigger Date

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Any deferred portion will only be paid if the participant is employed by the Company, or has terminated employment by reason of retirement, death or disability (as provided in Plan II). Payments are subject to certain other restrictions contained in Plan II.

These awards under both plans discussed above have been accounted for as liability awards under ASC 718. The Company recognized a benefit of $0.9 million for 2010 and expense of $1.2 million for 2009, which is included in General and Administrative Expense in the Consolidated Statement of Operations.

13. Derivative Instruments and Hedging Activities

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and not subjecting the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. As of December 31, 2010, the Company had 11 derivative contracts open: four natural gas price swap arrangements, six natural gas basis swaps arrangements and one crude oil collar arrangement. During 2010, the Company entered into six new derivative contracts covering anticipated crude oil production for 2010 and natural gas and crude oil production for 2011.

As of December 31, 2010, the Company had the following outstanding commodity derivatives:

Commodity and Derivative Type	Weighted-Average Contract Price	Volume		Contract Period
Derivatives Designated as Hedging Instruments
Natural Gas Swaps	$6.24 per Mcf		12,909 Mmcf	January - December 2011
Crude Oil Collars	$93.25 Ceiling / $80.00 Floor per Bbl		365 Mbbl	January - December 2011
Derivatives Not Designated as Hedging Instruments
Natural Gas Basis Swaps	$(0.27) per Mcf		16,123 Mmcf	January - December 2012

The change in fair value of derivatives designated as hedges that is effective is recorded to Accumulated Other Comprehensive Income in Stockholders’ Equity in the Consolidated Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as hedges, and the change in fair value of derivatives not designated as hedges, are recorded currently in earnings as a component of Natural Gas Revenue and Crude Oil and Condensate Revenue, as appropriate, in the Consolidated Statement of Operations.

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The following schedules reflect the fair value of derivative instruments on the Company’s consolidated financial statements:

Effect of Derivative Instruments on the Consolidated Balance Sheet

		Fair Value Asset (Liability)
(In thousands)	Balance Sheet Location	December 31, 2010			December 31, 2009
Derivatives Designated as Hedging Instruments
Natural Gas Commodity Contracts	Derivative Contracts (current assets)	$	18,669		$	99,151
Crude Oil Commodity Contracts	Derivative Contracts (current assets)		—			15,535
Natural Gas Commodity Contracts	Accrued Liabilities		—			(425	)
Crude Oil Commodity Contracts	Derivative Contracts (current assets)		(1,743	)		—
			16,926			114,261
Derivatives Not Designated as Hedging Instruments
Natural Gas Commodity Contracts	Other Liabilities		(2,180	)		(1,954	)
		$	14,746		$	112,307

At December 31, 2010 and 2009, unrealized gains of $16.9 million ($10.5 million, net of tax) and $114.3 million ($71.9 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income. Based upon estimates at December 31, 2010, the Company expects to reclassify $10.5 million in after-tax income associated with its commodity hedges from Accumulated Other Comprehensive Income to the Consolidated Statement of Operations over the next 12 months.

Effect of Derivative Instruments on the Consolidated Statement of Operations

Derivatives Designated as Hedging Instruments (In thousands)	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)							Location of Gain (Loss) Reclassified from Accumulated OCI into Income (In thousands)	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Twelve Months Ended December 31,								Twelve Months Ended December 31,
	2010		2009			2008			2010		2009		2008
Natural Gas Commodity
Contracts	$	74,903	$	161,330		$	314,738	Natural Gas Revenues	$	154,960	$	371,915	$	17,972
Crude Oil Contracts		752		(7,244	)		46,213	Crude Oil and Condensate Revenues		18,030		23,112		(4,951	)
	$	75,655	$	154,086		$	360,951		$	172,990	$	395,027	$	13,021

For the years ended December 31, 2010, 2009 and 2008, respectively, there was no ineffectiveness recorded in our Consolidated Statement of Operations related to our derivative instruments.

Derivatives Not Designated as Hedging Instruments	Location of Gain  (Loss) Recognized in Income on Derivative	Twelve Months Ended December 31,
(In thousands)		2010			2009			2008
Natural Gas Commodity Contracts	Natural Gas Revenues	$	(226	)	$	(1,954	)	$	—

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Additional Disclosures about Derivative Instruments and Hedging Activities

The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligation under the agreement. The Company enters into derivative contracts with multiple counterparties in order to limit its exposure to individual counterparties. The Company also has netting arrangements with all of its counterparties that allow it to offset payables against receivables from separate derivative contracts with that counterparty.

The counterparties to the Company’s derivative instruments are also lenders under its credit facility. The Company’s credit facility and derivative instruments contain certain cross default and acceleration provisions that may require immediate payment of its derivative liability in certain situations.

14. Fair Value Measurements

Effective January 1, 2009, the Company applied all of the provisions of ASC 820 and there was not a material impact on the Company’s financial statements except for the Company’s impairment of oil and gas properties. The Company previously adopted the guidance as it relates to financial assets and liabilities that are measured at fair value on a recurring basis effective January 1, 2008. In the future, areas that could cause an impact would primarily be limited to asset impairments, including long-lived assets, asset retirement obligations and assets acquired and liabilities assumed in a business combination, if any.

As defined in ASC 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The valuation techniques that can be used under ASC 820 are the market approach, income approach or cost approach. The market approach uses prices and other information for market transactions involving identical or comparable assets or liabilities, such as matrix pricing. The income approach uses valuation techniques to convert future amounts to a single discounted present value amount based on current market conditions about those future amounts, such as present value techniques, option pricing models (i.e. Black-Scholes model) and binomial models (i.e. Monte-Carlo model). The cost approach is based on current replacement cost to replace an asset.

The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. ASC 820 establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements, and accordingly, Level 1 measurements should be used whenever possible.

The three levels of the fair value hierarchy as defined by ASC 820 are as follows:

• Level 1: Valuations utilizing quoted, unadjusted prices for identical assets or liabilities in active markets that the Company has the ability to access. This is the most reliable evidence of fair value and does not require a significant degree of judgment. Examples include exchange-traded derivatives and listed equities that are actively traded.

• Level 2: Valuations utilizing quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially

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the full term of the asset or liability. Financial instruments that are valued using models or other valuation methodologies are included. Models used should primarily be industry-standard models that consider various assumptions and economic measures, such as interest rates, yield curves, time value, volatilities, contract terms, current market prices, credit risk or other market-corroborated inputs. Examples include most over-the-counter derivatives (non-exchange traded), physical commodities, most structured notes and municipal and corporate bonds.

• Level 3: Valuations utilizing significant, unobservable inputs. This provides the least objective evidence of fair value and requires a significant degree of judgment. Inputs may be used with internally developed methodologies and should reflect an entity’s assumptions using the best information available about the assumptions that market participants would use in pricing an asset or liability. Examples include certain corporate loans, real-estate and private equity investments and long-dated or complex over-the-counter derivatives.

Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under ASC 820, the lowest level that contains significant inputs used in valuation should be chosen. In accordance with ASC 820, the Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values.

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as asset retirement obligations and impairments of long-lived assets, at fair value on a nonrecurring basis. During the year ended December 31, 2010, the Company recorded impairment charges related to certain assets. Refer to Note 2 for additional disclosures related to fair value associated with the impaired assets. As none of the Company’s other non-financial assets and liabilities were impaired as of December 31, 2010 and 2009 and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures were not provided.

Financial Assets and Liabilities

Our financial assets and liabilities are measured at fair value on a recurring basis. The following fair value hierarchy table presents information about the Company’s financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2010 and 2009:

(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level  1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance as of December 31, 2010
Assets
Rabbi Trust Deferred Compensation Plan	$	15,788	$	—	$	—		$	15,788
Derivative Contracts		—		—		16,926			16,926
Total Assets	$	15,788	$	—	$	16,926		$	32,714
Liabilities
Rabbi Trust Deferred Compensation Plan	$	21,600	$	—	$	—		$	21,600
Derivative Contracts		—		—		(2,180	)		(2,180	)
Total Liabilities	$	21,600	$	—	$	(2,180	)	$	19,420

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(In thousands)	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Balance as of December 31, 2009
Assets
Rabbi Trust Deferred Compensation Plan	$	10,031	$	—	$	—	$	10,031
Derivative Contracts		—		—		114,686		114,686
Total Assets	$	10,031	$	—	$	114,686	$	124,717
Liabilities
Rabbi Trust Deferred Compensation Plan	$	19,087	$	—	$	—	$	19,087
Derivative Contracts		—		—		2,379		2,379
Total Liabilities	$	19,087	$	—	$	2,379	$	21,466

The Company’s investments associated with its Rabbi Trust Deferred Compensation Plan consist of mutual funds and deferred shares of the Company’s common stock that are publicly traded and for which market prices are readily available. The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The Company measured the nonperformance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions. The resulting reduction to the net receivable derivative contract position was $0.1 million. In times where the Company has net derivative contract liabilities, the nonperformance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

The following table sets forth a reconciliation of changes for the years ended December 31, 2010 and 2009 in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

	December 31,
(In thousands)	2010			2009			2008
Balance at beginning of period	$	112,307		$	355,202		$	7,272
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings(1)		172,764			393,073			13,021
Included in Other Comprehensive Income		(97,335	)		(240,941	)		347,930
Purchases, Issuances and Settlements		(172,990	)		(395,027	)		(13,021	)
Transfers In and/or Out of Level 3		—			—			—
Balance at end of period	$	14,746		$	112,307		$	355,202

⁽¹⁾ A loss of $0.2 million and $2.0 million for the years ended December 31, 2010 and 2009, respectively was unrealized and included in Natural Gas Revenues in the Statement of Operations. All gains included in earnings for the year ended December 31, 2008 were realized.

There were no transfers between Level 1 and Level 2 measurements for the year ended December 31, 2010.

Fair Value of Other Financial Instruments

The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments.

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The fair value of long-term debt is the estimated cost to acquire the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company’s default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company’s fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes and credit facility is based on interest rates currently available to the Company.

The Company uses available market data and valuation methodologies to estimate the fair value of debt. The carrying amounts and fair values of long-term debt are as follows:

	December 31, 2010				December 31, 2009
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-Term Debt	$	975,000	$	1,100,830	$	805,000	$	863,559

15. Earnings per Common Share

Basic EPS is computed by dividing net income (the numerator) by the weighted-average number of common shares outstanding for the period (the denominator). Diluted EPS is similarly calculated except that the denominator is increased using the treasury stock method to reflect the potential dilution that could occur if outstanding stock options and stock appreciation rights were exercised and stock awards were vested at the end of the applicable period.

The following is a calculation of basic and diluted weighted-average shares outstanding for the years ended December 31, 2010, 2009 and 2008:

	December 31,
	2010		2009		2008
Weighted-Average Shares—Basic		103,911,431		103,615,971		100,736,562
Dilution Effect of Stock Options, Stock Appreciation Rights and Stock Awards at End of Period		1,283,354		1,066,776		989,936
Weighted-Average Shares—Diluted		105,194,785		104,682,747		101,726,498
Weighted-Average Stock Awards and Shares Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect		283,566		260,818		258,074

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16. Accumulated Other Comprehensive Income / (Loss)

Changes in the components of accumulated other comprehensive income / (loss), net of taxes, for the years ended December 31, 2010, 2009 and 2008 were as follows:

	Net Gains / (Losses) on Cash Flow Hedges			Defined Benefit Pension and Postretirement Plans			Foreign Currency Translation Adjustment			Total
Balance at December 31, 2007	$	4,553		$	(14,027	)	$	8,580		$	(894	)
Net change in unrealized gain on cash flow hedges, net of taxes of $(129,415)		218,515			—			—			218,515
Net change in defined benefit pension and postretirement plans, net of taxes of $9,235		—			(15,581	)		—			(15,581	)
Change in foreign currency translation adjustment, net of taxes of $9,292		—			—			(15,614	)		(15,614	)
Balance at December 31, 2008	$	223,068		$	(29,608	)	$	(7,034	)	$	186,426
Net change in unrealized gain on cash flow hedges, net of taxes of $89,745		(151,196	)		—			—			(151,196	)
Net change in defined benefit pension and postretirement plans, net of taxes of $(162)		—			259			—			259
Change in foreign currency translation adjustment, net of taxes of $(4,116)		—			—			6,947			6,947
Balance at December 31, 2009	$	71,872		$	(29,349	)	$	(87	)	$	42,436
Net change in unrealized gain on cash flow hedges, net of taxes of $35,957		(61,378	)		—			—			(61,378	)
Net change in defined benefit pension and postretirement plans, net of taxes of (9,088)		—			15,227			—			15,227
Change in foreign currency translation adjustment, net of taxes of ($20)		—			—			32			32
Balance at December 31, 2010	$	10,494		$	(14,122	)	$	(55	)	$	(3,683	)

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CABOT OIL & GAS CORPORATION

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Estimates of total proved reserves at December 31, 2010, 2009 and 2008 were based on studies performed by the Company’s petroleum engineering staff. The 2010 and 2009 estimates were computed using the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year, as prescribed under the revised rules codified in ASC 932, “Extractive Activities—Oil and Gas”. The 2008 estimates were computed based on year end prices for oil and natural gas. The estimates were audited by Miller and Lents, Ltd., who indicated that based on their investigation and subject to the limitations described in their audit letter, they believe the results of those estimates and projections were reasonable in the aggregate.

No major discovery or other favorable or unfavorable event after December 31, 2010, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

As of December 31, 2009, the Company adopted the guidance in ASC 932 related to oil and gas reserve estimation and disclosures in conjunction with the year-end reserve reporting as a change in accounting principle that is inseparable from a change in accounting estimate. The impact of the adoption of this guidance on the Company’s financial statements was not practicable to estimate due to the challenges associated with computing a cumulative effect of adoption by preparing reserve reports under both the old and new guidance.

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The following tables illustrate the Company’s net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated, as estimated by the Company’s engineering staff. All reserves are located within the continental United States in 2010 and 2009 and, to a lesser extent, Canada in 2008.

	Natural  Gas (Mmcf)			Oil &  Liquids (Mbbl)			Total (Mmcfe)(1)
December 31, 2007(5)		1,559,953			9,328			1,615,919
Revision of Prior Estimates(2)		(47,745	)		(1,593	)		(57,302	)
Extensions, Discoveries and Other Additions		297,089			1,134			303,895
Production.		(90,425	)		(794	)		(95,191	)
Purchases of Reserves in Place		167,262			1,268			174,872
Sales of Reserves in Place		(141	)		(2	)		(156	)
December 31, 2008(5)		1,885,993			9,341			1,942,037
Revision of Prior Estimates(3)		(193,767	)		(1,062	)		(200,143	)
Extensions, Discoveries and Other Additions		459,612			544			462,880
Production		(97,914	)		(844	)		(102,976	)
Purchases of Reserves in Place		9			—			9
Sales of Reserves in Place		(40,771	)		(196	)		(41,949	)
December 31, 2009		2,013,162			7,783			2,059,858
Revision of Prior Estimates(4)		139,016			(379	)		136,742
Extensions, Discoveries and Other Additions		632,980			2,944			650,644
Production		(125,474	)		(858	)		(130,622	)
Purchases of Reserves in Place		593			4			617
Sales of Reserves in Place		(16,119	)		(3	)		(16,137	)
December 31, 2010		2,644,158			9,491			2,701,102
Proved Developed Reserves
December 31, 2007		1,133,937			7,026			1,176,091
December 31, 2008		1,308,155			6,728			1,348,521
December 31, 2009		1,288,169			6,082			1,324,663
December 31, 2010		1,681,451			7,129			1,724,225
Proved Undeveloped Reserves
December 31, 2007		426,016			2,302			439,828
December 31, 2008		577,838			2,613			593,516
December 31, 2009		724,993			1,701			735,199
December 31, 2010		962,707			2,362			976,877

⁽¹⁾ Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.

⁽²⁾ The majority of the revisions were the result of the decrease in the natural gas price.

⁽³⁾ The net downward revision of 200.1 Bcfe was primarily due to (i) downward revisions of 101.6 Bcfe due to lower 2009 oil and natural gas prices compared to 2008 and (ii) downward revisions of 120.4 Bcfe due to the removal of proved undeveloped reserves scheduled for development beyond five years primarily due to the application of the SEC’s oil and gas reserve calculation methodology effective beginning in 2009, partially offset by 21.9 Bcfe of positive performance revisions.

⁽⁴⁾ The net upward revision of 136.7 Bcfe was primarily due to (i) an upward performance revision of 284.4 Bcfe, primarily in the Dimock field in northeast Pennsylvania, and (ii) an upward revision of 35.0 Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of 182.7 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.

⁽⁵⁾ Prior to 2009, reserve estimates were based on year end prices.

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Capitalized Costs Relating to Oil and Gas Producing Activities

The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.

	December 31,
(In thousands)	2010		2009		2008
Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities	$	5,598,842	$	4,905,424	$	4,465,630
Aggregate Accumulated Depreciation, Depletion and Amortization		1,840,091		1,550,837		1,331,243
Net Capitalized Costs		3,758,751		3,354,587		3,134,387

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows:

	Year Ended December 31,
(In thousands)	2010		2009		2008
Property Acquisition Costs, Proved	$	801	$	394	$	605,860
Property Acquisition Costs, Unproved		130,675		145,681		152,666
Exploration Costs		66,368		68,196		82,972
Development Costs		630,511		379,140		600,269
Total Costs	$	828,355	$	593,411	$	1,441,767

Results of Operations for Producing Activities

The results of operations for the Company’s oil and gas producing activities were as follows:

	Year Ended December 31,
(In thousands)	2010		2009		2008
Operating Revenues	$	775,974	$	800,464	$	829,208
Costs and Expenses
Production		120,322		121,087		140,763
Exploration		42,725		50,784		31,200
Depreciation, Depletion and Amortization		364,452		265,402		259,399
Total Costs and Expenses		527,499		437,273		431,362
Income Before Income Taxes		248,475		363,191		397,846
Provision for Income Taxes		94,293		133,312		146,361
Results of Operations	$	154,182	$	229,879	$	251,485

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing the guidance in ASC 932 and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:

• Future costs and selling prices will probably differ from those required to be used in these calculations.

• Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.

• Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.

• Future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows for 2010 and 2009 were estimated by using the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year, as prescribed under the revised rules codified in ASC 932 that the Company adopted on January 1, 2010, and by applying year end oil and gas prices to the estimated future production of year end proved reserves for 2008.

The average prices (adjusted for basis and quality differentials) related to proved reserves at December 31, 2010, 2009 and 2008 for natural gas ($ per Mcf) were $4.33, $3.84 and $5.66, respectively, and for oil ($ per Bbl) were $74.25, $55.41 and $40.15, respectively. Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations. ASC 932 requires the use of a 10% discount rate.

Management does not solely use the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.

Standardized Measure is as follows:

	Year Ended December 31,
(In thousands)	2010			2009			2008
Future Cash Inflows	$	12,147,617		$	8,170,009		$	11,050,932
Future Production Costs		(2,377,402	)		(2,353,974	)		(3,018,154	)
Future Development Costs		(1,670,796	)		(1,234,203	)		(1,354,780	)
Future Income Tax Expenses		(2,357,935	)		(1,089,282	)		(1,891,928	)
Future Net Cash Flows		5,741,484			3,492,550			4,786,070
10% Annual Discount for Estimated Timing of Cash Flows		(3,006,975	)		(1,860,815	)		(2,726,115	)
Standardized Measure of Discounted Future Net Cash Flows	$	2,734,509		$	1,631,735		$	2,059,955

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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is an analysis of the changes in the Standardized Measure:

	Year Ended December 31,
(In thousands)	2010			2009			2008
Beginning of Year	$	1,631,735		$	2,059,955		$	2,170,651
Discoveries and Extensions, Net of Related Future Costs		780,917			381,691			341,156
Net Changes in Prices and Production Costs		991,942			(861,939	)		(692,803	)
Accretion of Discount		164,189			236,520			300,766
Revisions of Previous Quantity Estimates		164,851			(159,531	)		(69,788	)
Timing and Other		(105,331	)		(104,117	)		(157,194	)
Development Costs Incurred		115,560			109,384			157,194
Sales and Transfers, Net of Production Costs		(481,556	)		(286,594	)		(688,657	)
Net Purchases / (Sales) of Reserves in Place		(16,124	)		(38,730	)		166,873
Net Change in Income Taxes		(511,674	)		295,096			531,757
End of Year	$	2,734,509		$	1,631,735		$	2,059,955

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CABOT OIL & GAS CORPORATION

SELECTED DATA (UNAUDITED)

QUARTERLY FINANCIAL INFORMATION

(In thousands , except per share amounts )	First		Second		Third		Fourth		Total
2010
Operating Revenues	$	212,556	$	195,474	$	219,130	$	216,875	$	844,035
Impairment of Oil & Gas Properties and Other Assets(1)		—		—		35,789		5,114		40,903
Operating Income(2)		60,589		52,068		22,274		131,508		266,439
Net Income(2)		28,696		21,682		3,899		49,109		103,386
Basic Earnings per Share		0.28		0.21		0.04		0.47		0.99
Diluted Earnings per Share		0.27		0.21		0.04		0.47		0.98
2009
Operating Revenues	$	233,939	$	204,824	$	207,021	$	233,492	$	879,276
Impairment of Oil & Gas Properties and Other Assets(1)		—		—		—		17,622		17,622
Operating Income(3)		89,897		54,239		74,723		63,410		282,269
Net Income(3)		47,580		25,502		38,897		36,364		148,343
Basic Earnings per Share		0.46		0.25		0.38		0.34		1.43
Diluted Earnings per Share		0.46		0.24		0.37		0.35		1.42

⁽¹⁾ For discussion of impairment of oil and gas properties, refer to Note 2 of the Notes to the Consolidated Financial Statements.

⁽²⁾ Operating Income and Net Income in the second and fourth quarters of 2010 contain a $10.3 million gain on the disposition of the Woodford shale prospect and an impairment loss of $5.8 million associated with the third quarter sale of certain oil and gas properties in Colorado in the second quarter of 2010 and a gain of $11.4 million related to the sale of certain oil and gas properties in the Texas Panhandle as well as a gain of $49.3 million associated with the sale of the Pennsylvania gathering infrastructure and a $40.7 million gain from the sale of the Company’s investment in Tourmaline in the fourth quarter of 2010, respectively.

⁽³⁾ Operating Income and Net Income in the first and second quarters of 2009 contain a $12.7 million gain on the disposition of Thornwood properties and a $16.0 million loss on the sale of Canadian properties, respectively.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Changes in Internal Control over Financial Reporting

As of December 31, 2010, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the fourth quarter that has materially affected, or is reasonably likely to materially effect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

The management of Cabot Oil & Gas Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Cabot Oil & Gas Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Cabot Oil & Gas Corporation’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we have concluded that, as of December 31, 2010, the Company’s internal control over financial reporting is effective at a reasonable assurance level based on those criteria.

The effectiveness of Cabot Oil & Gas Corporation’s internal control over financial reporting as of December 31, 2010, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting. In addition, the information set forth under the caption “Business-Other Business Matters-Corporate Governance Matters” in Item 1 regarding our Code of Business Conduct is incorporated by reference in response to this Item.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

A. INDEX

1. Consolidated Financial Statements

See Index on page 54.

2. Financial Statement Schedules

Financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is provided in the notes to our consolidated financial statements.

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3. Exhibits

The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith. Our commission file number is 1-10447.

Exhibit Number	Description
***2.1	Purchase and Sale Agreement dated June 3, 2008 by and among Enduring Resources, LLC, Mustang Drilling, Inc., Minden Gathering Services, LLC and Cabot Oil & Gas Corporation (Form 10-Q for the quarter ended June 30, 2008).
3.1	Restated Certificate of Incorporation of the Company (Form 8-K for January 21, 2010).
3.2	Amended and Restated Bylaws of the Company amended January 14, 2010 (Form 8-K for January 14, 2010).
4.1	Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553).
4.2	Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K for August 30, 2001).
	(a)    Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
	(b)    Amendment No. 2 to Note Purchase Agreement, dated as of September 28, 2010 (Form 10-Q for the quarter ended September 30, 2010).
4.3	Note Purchase Agreement dated as of July 16, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 8-K for July 16, 2008).
	(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
4.4	Note Purchase Agreement dated as of December 1, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 10-K for 2008).
	(a)    Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
4.5	Note Purchase Agreement dated as of December 30, 2010 among Cabot Oil & Gas Corporation and the Purchasers named therein.
4.6	Credit Agreement, dated as of September 22, 2010, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities LLC, as Syndication Agent, Bank of Montreal, as Documentation Agent, and the Lenders party thereto (Form 10-Q for the quarter ended September 30, 2010).
*10.1	Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 2008).
	(a)    Form of Change in Control Agreement between the Company and Certain Officers (Confirmation that Certain Benefits no Longer Apply).
*10.2	Form of Supplemental Executive Retirement Agreement (Form 10-K for 2008).
	(a)    Agreement Concerning SERP.
*10.3	1990 Non-employee Director Stock Option Plan of the Company (Form S-8) (Registration No. 33-35478).
	(a)    First Amendment to 1990 Non-employee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8) (Registration No. 33-35478).
	(b)    Second Amendment to 1990 Non-employee Director Stock Option Plan (Form 10-K for 1995).

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Exhibit Number	Description
*10.4	Second Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form 10-K for 2001).
*10.5	Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001).
*10.6	Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997).
*10.7	Deferred Compensation Plan of the Company, as Amended and Restated, Effective January 1, 2009 (Form 10-K for 2008).
	(a)    First amendment to the Deferred Compensation Plan of the Company, effective October 1, 2010.
	(b)    Second amendment to the Deferred Compensation Plan of the Company, effective October 26, 2010.
10.8	Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001).
10.9	Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998).
*10.10	Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001).
	(a)    Amendment to Employment Agreement between the Company and Dan O. Dinges, effective December 31, 2008 (Form 10-K for 2008).
*10.11	2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004).
	(a)    First Amendment to the 2004 Incentive Plan effective February 23, 2007 (Form 10-Q for the quarter ended March 31, 2007).
	(b)    Second Amendment to the 2004 Incentive Plan Amendment, effective as of January 1, 2009 (Form 10-K for 2008).
*10.12	2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004).
*10.13	2004 Annual Target Cash Incentive Plan Measurement Criteria for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).
*10.14	Form of Restricted Stock Awards Terms and Conditions for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).
*10.15	2005 Form of Non-Employee Director Restricted Stock Unit Award Agreement (Form 8-K for May 24, 2005).
*10.16	Savings Investment Plan of the Company, as amended and restated effective January 1, 2001 (Form 10-K for 2005).
	(a)    First Amendment to the Savings Investment Plan effective January 1, 2002 (Form 10-K for 2005).
	(b)    Second Amendment to the Savings Investment Plan effective January 1, 2003 (Form 10-K for 2005).
	(c)    Third Amendment to the Savings Investment Plan effective January 1, 2005 (Form 10-K for 2005).
*10.17	Forms of Award Agreements for Executive Officers under 2004 Incentive Plan (Form 10-K for 2006).
	(a)    Form of Restricted Stock Award Agreement (Form 10-K for 2006).
	(b)    Form of Stock Appreciation Rights Award Agreement (Form 10-K for 2006).
	(c)    Form of Performance Share Award Agreement (Form 10-K for 2006).

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Exhibit Number	Description
10.18	Cabot Oil & Gas Corporation Mineral, Royalty and Overriding Royalty Interest Plan (Registration Statement No. 333-135365).
	(a)    Form of Conveyance of Mineral and/or Royalty Interest (Registration Statement No. 333-135365).
	(b)    Form of Conveyance of Overriding Royalty Interest (Registration Statement No. 333-135365).
10.19	Purchase and Sale Agreement dated August 25, 2006 between Cabot Oil & Gas Corporation, a Delaware corporation, Cody Energy LLC, a Colorado limited liability company, and Phoenix Exploration Company LP, a Delaware limited partnership (Form 8-K for September 29, 2006).
*10.20	Form of Amendment of Employee Award Agreements (Form 8-K for December 19, 2006).
*10.21	Savings Investment Plan of the Company, as amended and restated effective January 1, 2006 (Form 10-K for 2006).
	(a)    First Amendment to the Savings Investment Plan of the Company effective January 1, 2006 (Form 10-K for 2007).
	(b)    Second Amendment to the Savings Investment Plan of the Company effective April 23, 2008 (Form 10-Q for the quarter ended March 31, 2008).
	(c)    Third Amendment to the Savings Investment Plan of the Company effective July 1, 2008 (Form 10-K for 2008).
	(d)    Fourth Amendment to the Savings Investment Plan of the Company effective January 1, 2008 (Form 10-K for 2008).
*10.22	Cabot Oil & Gas Corporation Pension Plan, as amended and restated effective September 30, 2010.
*10.23	Savings Investment Plan of the Company, as amended and restated effective January 1, 2009 (Form 10-K for 2009).
	(a)    First Amendment to the Savings Investment Plan of the Company effective January 1, 2009.
21.1	Subsidiaries of Cabot Oil & Gas Corporation.
23.1	Consent of PricewaterhouseCoopers LLP.
23.2	Consent of Miller and Lents, Ltd.
31.1	302 Certification—Chairman, President and Chief Executive Officer.
31.2	302 Certification—Vice President and Chief Financial Officer.
32.1	906 Certification.
99.1	Miller and Lents, Ltd. Audit Letter.
**101.INS	XBRL Instance Document.
**101.SCH	XBRL Taxonomy Extension Schema Document.
**101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
**101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
**101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.
**101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

* Compensatory plan, contract or arrangement.

** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

*** Certain schedules to the exhibit are omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish to the SEC, upon request, copies of any such schedules.

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SIGNATURES

Pursuant to the requirements of Section 13 and 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 28th of February 2011.

CABOT OIL & GAS CORPORATION
By:	/S/    DAN O. DINGES
	Dan O. Dinges
	Chairman, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/S/    DAN O. DINGES         Dan O. Dinges	Chairman, President and Chief Executive Officer (Principal Executive Officer)	February 28, 2011
/S/    SCOTT C. SCHROEDER         Scott C. Schroeder	Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)	February 28, 2011
/S/    TODD M. ROEMER         Todd M. Roemer	Controller (Principal Accounting Officer)	February 28, 2011
/S/    RHYS J. BEST         Rhys J. Best	Director	February 28, 2011
/S/    DAVID M. CARMICHAEL         David M. Carmichael	Director	February 28, 2011
/S/    JAMES R. GIBBS         James R. Gibbs	Director	February 28, 2011
/S/    ROBERT L. KEISER         Robert L. Keiser	Director	February 28, 2011
/S/    ROBERT KELLEY         Robert Kelley	Director	February 28, 2011
/S/    P. DEXTER PEACOCK         P. Dexter Peacock	Director	February 28, 2011
/S/    WILLIAM P. VITITOE         William P. Vititoe	Director	February 28, 2011

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