Index to Financial Statements

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.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, 20082010

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

1200 Enclave Parkway,Three Memorial City Plaza 840 Gessner Road, Suite 1400 Houston, Texas 7707777024

(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:

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.    Yesx    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¨    Nox

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.    Yesx    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).    Yesx    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-Kx.

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):

(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¨    Nox

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, 2008)2010) was approximately $7.0$3.3 billion.

As of February 19, 2009,18, 2011, there were 103,447,221104,277,128 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 28, 2009May 3, 2011 are incorporated by reference into Part III of this report.

Index to Financial Statements

TABLE OF CONTENTS

Index to Financial Statements

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 DEFINITIONSOIL AND GAS TERMS

The following is a listare abbreviations and definitions of certain terms commonly used termsin the oil and their definitionsgas industry and included within this Annual Report on Form 10-K:

IndexBbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to Financial Statements

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 termsstructural feature andstratigraphic 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

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 America. Our four principal areas of operation areregion and combining the AppalachianAnadarko Basin onshore Gulf Coast, including south and eastwith our Texas and north Louisiana areas to form the Rocky MountainsSouth region. Certain prior period amounts and the Anadarko Basin. We also operate in the deep gas basin of Western Canada.historical descriptions have been reclassified to reflect this reorganization. Operationally, we now have fourtwo primary regional offices located in Houston, Texas; Charleston, West Virginia; Denver, Colorado;Texas and Calgary, Alberta.Pittsburgh, Pennsylvania.

In 2008, energy commodity2010, natural gas prices increased to all-time highdecreased from the price levels for the first half of the year and then quickly declined to 2007 levelsexperienced during the second half of 2008.2009, while crude oil prices increased. Our 20082010 average realized natural gas price was $8.39$5.54 per Mcf, 16% higher26% lower than the 20072009 average realized price of $7.23$7.47 per Mcf. Our 20082010 average realized crude oil price was $89.11$97.91 per Bbl, 33%14% higher than the 20072009 average realized price of $67.16$85.52 per Bbl. These realized prices include realized gains and losses resulting from commodity derivatives (zero-cost collars or swaps).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 2008, we pursued and completed the largest2010, our investment program in our history, totaling $1,481.0 million. This included our largest producing property acquisition ($625.0 million),totaled $891.5 million, including lease acquisition ($152.7130.7 million) and drilling and facilities ($624.3654.2 million) programs. The producing property and lease acquisition activity were funded by issuances of new long-term debt and common stock during the year. TheOur capital spending (excluding the acquisition activity) was funded largely through cash on hand, operating cash flow, from operations and, to a lesser extent, borrowings on our revolving credit facility.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 that we have sufficient liquidity, including cash resources and we intend to maintain spending discipline.available credit. We believe these strategies continue to beare 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 believesold our balance sheetexisting Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and availability undertwo 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 sufficient liquiditysuch increased commitment amount. The amended facility provides for a $1.5 billion borrowing base and extends the term of the agreement to pursueSeptember 2015.

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In April 2009, we sold substantially all of our 2009 program.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 (see Note 2 of the Notes to the Consolidated Financial Statements for further details).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, (see Note 9 of the Notes to the Consolidated Financial Statements for further details), and we closed a private placement in July 2008 of $425 million principal amount of 6.51% weighted average senior unsecured fixed rate notes (see Note 4 of the Notes to the Consolidated Financial Statements for further details).notes.

On an equivalent basis, our production level in 20082010 increased by 11%27% from 2007.2009. We produced 95.2130.6 Bcfe, or 260.1357.9 Mmcfe per day, in 2008,2010, as compared to 85.5103.0 Bcfe, or 234.1282.1 Mmcfe per day, in 2007.2009. Natural gas production increased to 90.4125.5 Bcf in 20082010 from 80.597.9 Bcf in 20072009, primarily due to(1) increased natural gas production in the Gulf Coast region due to increased production in the Minden field, largely due toNorth region associated with the properties we acquiredincreased drilling program and the Lathrop compressor station in Susquehanna County, Pennsylvania. The decline in the east Texas acquisitionother areas is related to natural production decline. Oil production decreased by 10 Mbbls from 818 Mbbls in August 2008, and increased drilling2009 to 808 Mbbls in the County Line field,(2) increased2010 due primarily to a decrease in production in the West region associated with an increaseNorth and a decrease in the drilling program, (3) increased production in the East region due to increased drilling activity in West Virginia and northeastern Pennsylvania and(4) increased production in Canada due to the sale of our Canadian properties in April 2009, partially offset by increased drilling activityproduction in the Hinton field. Oil production decreased by 41 Mbbls from 823 Mbbls in 2007 to 782 Mbbls in 2008 due primarily to natural declines inSouth region associated with the Gulf CoastEagle Ford shale and West regions.Pettet formation production.

Index to Financial Statements

For the year ended December 31, 2008,2010, we drilled 432113 gross wells (355(87.1 net) with a success rate of 97%98% compared to 461143 gross wells (391(118.6 net) with a success rate of 96%95% for the prior year. In 2009,2011, we plan to drill approximately 148110 gross wells (122.3(83.1 net). The number of wells we plan to drill in 2009 is down from 2008 primarily due to lower commodity prices resulting from the global decline in economic activity as well as our ongoing strategy of managing our capital investment program within anticipated cash flow. We plan to concentrate, focusing our capital program for 2009 in east Texas andthe Marcellus shale in northeast Pennsylvania where opportunities for growth are currently concentrated.and the Eagle Ford shale in south Texas.

Our 20082010 total capital and exploration spending was $1.5 billion$891.5 million compared to $636.2$640.4 million of total capital and exploration spending in 2007.2009. In both 20082010 and 2007,2009, 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 2009.2011. Funding of the program is expected to be provided by operating cash flow, existing cash and, increasedif required, borrowings under our credit facility, if required. We may also reduce our budgeted capital and exploration spending to maintain sufficient liquidity. We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position.facility. For 2009,2011, the Gulf Coast and East regions areNorth region is expected to receive approximately 90%58% of the anticipated capital program, with the majority of the remainderremaining 42% dedicated to the WestSouth region. We believe these strategies are appropriate in the current industry environment and will continue to add shareholder value over the long-term. In 2009,2011, we plan to spend approximately $475$600 million on capital and exploration activities.

Our proved reserves totaled approximately 1,9422,701 Bcfe at December 31, 2008,2010, of which 97%98% were natural gas. This reserve level was up by 20%31% from 1,6162,060 Bcfe at December 31, 20072009 on the strength of results from our drilling program,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 increaseDimock 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 capital spending and the east Texas acquisition.five-year development plan.

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The following table presents certain reserve, production and well information as of December 31, 2008.2010.

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 3.02.3 million gross acres. In addition, we own fee interest in approximately 0.2 million gross acres, primarily in West Virginia. Our ten largest fields,field (Dimock), which are fields with 2.5% or greateris our only field that contains more than 15% of total companyour proved reserves, makeis located in northeast Pennsylvania. This field makes up approximately 53%46% of total companyour proved reserves.

Index to Financial Statements

The following table presents certain information with respect to our principal properties as of and for the year ended December 31, 2008.Dimock field:

EASTNORTH REGION

The North region is comprised of the Appalachian and Rocky Mountains areas. Our East region activities in the Appalachian area are concentrated primarily in northeast Pennsylvania and in West VirginiaVirginia. Our activities in the Rocky Mountains area are concentrated in the Green River and Pennsylvania.Washakie Basins in Wyoming. This region is managed from our office in Charleston, West Virginia.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 20082010 were $369.6$603.6 million, or 24%68% of our total 20082010 capital and exploration expenditures, compared to $178.6$380.3 million for 2007,2009, or 28%60% of our total 20072009 capital and exploration

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expenditures. This increase in spending was substantially driven by a $103.1 million increasean expanded Marcellus horizontal drilling program in lease acquisition costs year-over-year.northeast Pennsylvania to hold acreage. For 2009,2011, we have budgeted approximately $200$350.0 million for capital and exploration expenditures in the region.

At December 31, 2008,2010, we had 3,3824,185 wells (3,162.6(3,588.5 net), of which 3,2683,724 wells are operated by us. There are multiple producing intervals in the Appalachian area that includeincludes the Big Lime, Weir, Berea and Devonian (including Marcellus) Shaleshale formations at depths primarily ranging from 1,100950 to 9,5007,800 feet, with an average depth of approximately 4,1004,050 feet. Average net daily productionIn the Rocky Mountains area, principal producing intervals are in 2008 was 69.1 Mmcfe. 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 crude oil/condensate/NGL production for 2008 was 25.2 Bcf and 23 Mbbls, respectively.

While natural gas production volumes from East reservoirsreserves in the North region are relatively low on a per-well basis compared to other areas ofprimarily associated with the United States, the productive life of East region reserves is relatively long.Marcellus shale. At December 31, 2008,2010, we had 871.82,007.2 Bcfe of proved reserves (substantially all natural gas) in the EastNorth region, constituting 45%74% of our total proved reserves. Developed and undeveloped reserves made up 613.41,251.3 Bcfe and 258.4755.9 Bcfe of the total proved reserves for the EastNorth region, respectively. While no properties are individually significant to our company as a whole, the Sissonville, Pineville, Logan-Holden-Dingess, Big Creek, Hernshaw-Bullcreek, and Huff Creek fields in West Virginia and the Dimock field in the Susquehanna area of Pennsylvania are included in our ten largest fields and together contain approximately 30% of our total company proved equivalent reserves.

Index to Financial Statements

In 2008,2010, we drilled 21263 wells (205.4(61.3 net) in the EastNorth region, of which 20862 wells (201.4(60.3 net) were development and extension wells. In 2009,2011, we plan to drill approximately 6354 wells (62.8(54.0 net), primarily in the Dimock field.field in northeast Pennsylvania.

In 2008,2010, we produced and marketed approximately 62221.8 Mmcf per day of natural gas and 272.5 barrels of crude oil/condensate/NGL per day in the EastNorth 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 3,2003,148 miles of pipeline with interconnects to three interstate transmission systems and seven local distribution companies and numerous end users as of the end of 2008.2010. 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 EastNorth region. The pipeline systems and storage fields are fully integrated with our operations.

The principal markets for our EastNorth region natural gas are in the northeastnortheastern 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 70%42% of our natural gas sales volume in the EastNorth region is sold at index-based prices under contracts with a termterms of one year or greater. In addition, spotThe 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. Approximately one percent of East production is sold on fixed price contracts that typically renew annually.

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GULF COASTSOUTH REGION

Our development, exploitation, exploration and production activities in the Gulf CoastSouth region are primarily concentrated in east and south Texas and north Louisiana.Oklahoma. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley, Haynesville, Bossier, and James Lime formations in north Louisiana and east Texas, and 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 2,200approximately 2,500 to 17,40017,700 feet, with an average depth of approximately 10,9008,950 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 $962.0$280.4 million for 2008,2010, or 64%32% of our total 20082010 capital and exploration expenditures, compared to $291.5$237.6 million for 2007,2009, or 46%37% of our total 20072009 capital and exploration expenditures. This increase in capital spending includes the $604.0 million paid for the east Texas acquisition. Of the total company year-over-year increase in capital and exploration expenditures, approximately 79% was attributableis primarily due to an increaselease acquisitions to establish a greater position in the Gulf Coast region spending.oil window of the Eagle Ford shale. For 2009,2011, we have budgeted approximately $230

Index to Financial Statements

$250 million for capital and exploration expenditures in the region. Our 2009 Gulf Coast2011 South region drilling program will emphasize activity primarily in eastthe Eagle Ford shale in south Texas.

We had 8441,769 wells (592.2(1,231.1 net) in the Gulf CoastSouth region as of December 31, 2008,2010, of which 6331,345 wells are operated by us. Average daily production in 20082010 was 104.1134.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 20082010 was 34.644.5 Bcf and 585759 Mbbls, respectively.

At December 31, 2008,2010, we had 554.6693.9 Bcfe of proved reserves (93% natural gas) in the Gulf CoastSouth region, which represented 29%26% of our total proved reserves. Developed and undeveloped reserves made up 317.3472.9 Bcfe and 237.3221.0 Bcfe of the total proved reserves for the Gulf CoastSouth region, respectively. While no properties are individually significant to our company as a whole, the Brachfield Southeast field in the Minden area and the Angie field in the County Line area, both in east Texas, are included in our ten largest fields based on percentage of our total company proved equivalent reserves and together contain approximately 20% of our total company proved equivalent reserves.

In 2008,2010, we drilled 9450 wells (63.9(25.8 net) in the Gulf CoastSouth region, of which 8347 wells (57.1(23.3 net) were development and extension wells. In 2009,2011, we plan to drill 6556 wells (47.4(29.1 net), primarily in east Texas, including the Minden and County Line fields.Eagle Ford shale in south Texas.

Our principal markets for Gulf Coastthe South region natural gas are in the industrialized Gulf Coast area and the northeastMidwestern United States. We sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Currently, approximately 70%83% of our natural gas sales volumes in the Gulf CoastSouth region are sold at index-based prices under contracts with terms of one year or greater. The remaining 30%17% of our natural gas sales volumes are sold at index-based prices under short-term agreements. The Gulf CoastSouth 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 2008,2010, we produced and marketed approximately 1,598122.0 Mmcf per day of natural gas and 2,079.1 barrels of crude oil/condensate/NGL per day in the Gulf CoastSouth region at market responsive prices.

WEST REGION

Our activities in the West region, which is comprised of the Rocky Mountains and Mid-Continent areas, are managed by a regional office in Denver, Colorado. At December 31, 2008, we had 475.3 Bcfe of proved reserves (97% natural gas) in the West region, constituting 24% of our total proved reserves. Developed and undeveloped reserves made up 380.3 Bcfe and 95.0 Bcfe of the total proved reserves for the West region, respectively. While no properties are individually significant to our company as a whole, the Mocane-Laverne field in Oklahoma in the Mid-Continent area is included within our ten largest fields and contains approximately three percent of our total company proved equivalent reserves.

Our principal markets for West region natural gas are in the northwest and midwest United States. We sell natural gas to power generators, natural gas processors, local distribution companies, industrial customers and marketing companies. Currently, approximately 90% of our natural gas production in the West region is sold primarily under contracts with a term of one to three years at index-based prices. Another nine percent of the natural gas production is sold under short-term arrangements at index-based prices, and the remaining one percent is sold under certain fixed-price contracts. The West region properties are connected to the majority of the midwest and northwest interstate and intrastate pipelines, affording us access to multiple markets.

In 2008, we produced and marketed approximately 451 barrels of crude oil/condensate/NGL per day in the West region at market responsive prices.

Index to Financial Statements

Rocky Mountains

Activities in the Rocky Mountains are concentrated in the Green River and Washakie Basins in Wyoming and Paradox Basin in Colorado. At December 31, 2008, we had 271.4 Bcfe of proved reserves (96% natural gas) in the Rocky Mountains area, or 14% of our total proved reserves.

Capital and exploration expenditures in the Rocky Mountains were $88.7 million for 2008, or six percent of our total 2008 capital and exploration expenditures, compared to $54.7 million for 2007, or nine percent of our total 2007 capital and exploration expenditures. For 2009, we have budgeted approximately $29 million for capital and exploration expenditures in the area.

We had 716 wells (329.4 net) in the Rocky Mountains area as of December 31, 2008, of which 372 wells are operated by us. Principal producing intervals in the Rocky Mountains area are in the Almond, Frontier, Dakota and Honaker Trail formations at depths ranging from 4,200 to 14,375 feet, with an average depth of approximately 10,900 feet. Average net daily production in the Rocky Mountains during 20082010 was 41.3134.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 20082010 was 14.544.5 Bcf and 95759 Mbbls, respectively.

In 2008, we drilled 49 wells (31.3 net) in the Rocky Mountains, of which 47 wells (30.8 net) were development wells. In 2009, we plan to drill 8 wells (5.9 net), primarily in Wyoming, including the Cow Hollow and Lincoln Road fields.

Mid-Continent

Our Mid-Continent activities are concentrated in the Anadarko Basin in southwest Kansas, Oklahoma and the panhandle of Texas. At December 31, 2008, we had 203.9 Bcfe of proved reserves (98% natural gas) in the Mid-Continent area, or 10% of our total proved reserves.

Capital and exploration expenditures were $60.3 million for 2008, or four percent of our total 2008 capital and exploration expenditures, compared to $54.5 million for 2007, or eight percent of our total 2007 capital and exploration expenditures. For 2009, we have budgeted approximately $10 million for capital and exploration expenditures in the area.

As of December 31, 2008, we had 844 wells (594.5 net) in the Mid-Continent area, of which 659 wells are operated by us. Principal producing intervals in the Mid-Continent are in the Chase, Morrow and Chester formations at depths ranging from 2,200 to 17,450 feet, with an average depth of approximately 7,050 feet. Average net daily production in 2008 was 33.9 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2008 was 12.0 Bcf and 70 Mbbls, respectively.

In 2008, we drilled 71 wells (50.6 net) in the Mid-Continent, all of which were development and extension wells. In 2009, we plan to drill 12 wells (6.1 net), primarily in Oklahoma, including the Gage and Cederdale Northeast fields.

CANADA REGION

Our activities in the Canada region are managed by a regional office in Calgary, Alberta. Our Canadian exploration, development and producing activities are concentrated in the Province of Alberta. At December 31, 2008, we had 40.3 Bcfe of proved reserves (97% natural gas) in the Canada region, constituting two percent of our total proved reserves. Developed and undeveloped reserves made up 37.5 Bcfe and 2.8 Bcfe of the total proved reserves for the Canada region, respectively. No properties in the Canada region are individually significant to our company as a whole. The largest field in this region is the Hinton field in Alberta, which is not included in our ten largest fields.

Capital and exploration expenditures in Canada were $25.4 million for 2008, or two percent of our total 2008 capital and exploration expenditures, compared to $55.1 million for 2007, or nine percent of our total 2007

Index to Financial Statements

capital and exploration expenditures. For 2009, we have budgeted approximately $1 million for capital and exploration expenditures in the area.

We had 43 wells (16.2 net) in the Canada region as of December 31, 2008, of which 25 wells are operated by us. Principal producing intervals in the Canada region are in the Falher, Bluesky, Cadomin, Dunvegan and the Mountain Park formations at depths ranging from 8,500 to 14,500 feet, with an average depth of approximately 11,050 feet. Average net daily production in Canada during 2008 was 11.7 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2008 was 4.1 Bcf and 21 Mbbls, respectively.

In 2008, we drilled six wells (3.4 net) in Canada, of which four wells (2.6 net) were development and extension wells. In 2009, we do not plan to drill any wells in Canada.

Our principal markets for Canada natural gas are in western Alberta. We sell natural gas to gas marketers. Currently, all of our natural gas production in Canada is sold primarily under contracts with a term of one year at index-based prices. The Canadian properties are connected to the major interstate pipelines.

In 2008, we produced and marketed approximately 59 barrels of crude oil/condensate per day in the Canada region at market responsive prices.

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 20082010 we employed natural gas and crude oil price collar and swap agreements for portions of our 2008 through 2010 production to attempt to manage price risk more effectively. In 2007During 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 2006, we primarily employedcrude 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 2008, collars2010, swaps covered 60%29% of natural gas production and had a weighted-average floor of $8.53 per Mcf and a weighted-average ceiling of $10.70 per Mcf. At December 31, 2008, natural gas price collars for the year ending December 31, 2009 will cover 47,253 Mmcf of production at a weighted-average floor of $9.40 per Mcf and a weighted-average ceiling of $12.39 per Mcf. For 2008, collars covered 47%90% of crude oil production and had a floor of $60.00 per Bbl and a ceiling of $80.00 per Bbl.

For 2008, swaps covered 11% of natural gas production and had a weighted-average price of $10.27 per Mcf. At December 31, 2008, natural gas price swaps for the years ending December 31, 2009 and 2010 will cover 16,079 Mmcf and 19,295 Mmcf of production, respectively, at a weighted-average price of $12.18$9.30 per Mcf and $11.43$104.25 per Mcf,Bbl, respectively. For 2008, a swap covered 12%

As of crude oil production and had a fixed price of $127.15 per Bbl. Crude oil price swaps for the years ending December 31, 2009 and 2010, will cover 365 Mbbls each at a fixed price of $125.25 per Bbl and $125.00 per Bbl, respectively. Our decision to hedge 2009 and 2010 production fits with our risk management strategy and allows us to lock inwe had the benefit of highfollowing outstanding commodity prices on a portion of our anticipated production. During January 2009, we entered into basis swaps in the Gulf Coast region that will cover 16,079 Mmcf of anticipated 2012 natural gas production at fixed basis differentials per Mcf of $(0.26) to $(0.27).derivatives:

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.

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RESERVES

Current Reserves

The following table presents our estimated proved reserves at December 31, 2008.2010.

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 hereherein were prepared by our petroleum engineering staff and reviewedaudited 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;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 used appropriate engineering, geologicrelied were adequate and evaluation principlesof sufficient quality, and techniques in accordance with practices generally accepted in(4) the petroleum industry in makingresults of our estimates and projections and our total proved reserves are, in the aggregate, reasonable. For additional information regarding estimates of proved reserves, the reviewaudit 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 reviewaudit letter by Miller and Lents, Ltd., dated February 1, 2011, has been filed as an exhibit to this Form 10-K. Our estimates of proved reserves in the table above are consistent with those filed by us with other federal agencies. During 2008, we filed estimates of our oil and gas reserves for the year 2007 with the Department of Energy. These estimates differ by five percent or less from the reserve data presented. Our reserves are sensitive to natural gas and crude oil sales prices and their effect on the economic productive life of producing rates.properties. Our reserves are based on 12-month average oil and gas index prices, in effect oncalculated as the lastunweighted arithmetic average for the first day of December 2008.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.

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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.

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VolumesProduction and Prices: Production CostsSales

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.

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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, 2008.2010. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

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Total Net Leasehold Acreage by Region of Operation

Total Net Undeveloped Acreage Expiration by Region of Operation

The following table presents our net undeveloped acreage expiring over the next three years by operating region as of December 31, 2008.2010. The figures below assume no future successful development or renewal of undeveloped acreage.

Well Summary

The following table presents our ownership at December 31, 2008, in productive natural gas and oil wells in the Eastby region (consisting primarily of various fields located in West Virginia and Pennsylvania), in the Gulf Coast region (consisting primarily of various fields located in Louisiana and Texas), in the West region (consisting of various fields located in Oklahoma, Kansas, Colorado, Utah and Wyoming) and in the Canada region (consisting of various fields located in the Province of Alberta).at December 31, 2010. This summary includes natural gas and oil wells in which we have a working interest.

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Drilling Activity

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