Index to Financial Statements

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, 20092010

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

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:

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-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):

(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, 2009)2010) was approximately $3.2$3.3 billion.

As of February 22, 2010,18, 2011, there were 103,821,454104,277,128 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 27, 2010May 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 North America.the United States. In 2009, we restructured our operations by combining our Rocky Mountain and Appalachian areas to form the North Regionregion and combining the Anadarko Basin with our Texas and Louisiana areas to form the South Region.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 2009, energy commodity2010, natural gas prices recovereddecreased from the price levels experienced during the second half of 2008.2009, while crude oil prices increased. Our 20092010 average realized natural gas price was $7.47$5.54 per Mcf, 11%26% lower than the 20082009 average realized price of $8.39$7.47 per Mcf. Our 20092010 average realized crude oil price was $85.52$97.91 per Bbl, 4% lower14% higher than the 20082009 average realized price of $89.11$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 2009,2010, our investment program totaled $640.4$891.5 million, including lease acquisition ($145.7130.7 million) and drilling and facilities ($401.1654.2 million) programs. Our capital spending 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 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 private Canadian company (see Note 2$40.7 million gain on sale of the Notes to the Consolidated Financial Statementsassets.

In 2010, we sold various other properties for further details). In April 2009, we also entered into a new revolving credit facilitytotal proceeds of $30.4 million and terminated our prior credit facility (see Note 4an aggregate gain of the Notes to the Consolidated Financial Statements for further details).$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 20092010 increased by 8%27% from 2008.2009. 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, as compared to 95.2 Bcfe, or 260.1 Mmcfe per day, in 2008.2009. Natural gas production increased to 125.5 Bcf in 2010 from 97.9 Bcf in 2009, from 90.4 Bcf in 2008, primarily due to increased production in the North region associated with the increased drilling program and the Lathrop compressor station in Susquehanna County, Pennsylvania as well as increased natural gas productionPennsylvania. The decline in the South region associated with the properties we acquired in the east Texas acquisition in August 2008 and drilling in the Angie field in east Texas. Partially offsetting theseother areas is related to natural production gains were decreases in production in Canada due to the sale of our Canadian properties in April 2009, as well as reduced drilling activity in Oklahoma and Wyoming.decline. Oil production increaseddecreased by 3610 Mbbls from 782 Mbbls in

Index to Financial Statements

2008 to 818 Mbbls in 2009 to 808 Mbbls in 2010 due primarily to increaseda decrease in production in the South region associated with the properties we acquired in the east Texas acquisition in August 2008North and an increase related to Pettet development in the Angie field, partially offset by a decrease in production in Canada due to the sale of our Canadian properties in April 2009.2009, 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, 2009,2010, we drilled 113 gross wells (87.1 net) with a success rate of 98% compared to 143 gross wells (119(118.6 net) with a success rate of 95% compared to 432 gross wells (355 net) with a success rate of 97% for the prior year. In 2010,2011, we plan to drill approximately 136110 gross wells (123.9(83.1 net), focusing our capital program in the Marcellus Shaleshale in northeast Pennsylvania and to a lesser extent,the Eagle Ford shale in eastsouth Texas.

Our 20092010 total capital and exploration spending was $640.4$891.5 million compared to $1.5 billion of total capital and exploration spending$640.4 million in 2008.2009. In both 20092010 and 2008,2009, 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 2010.2011. 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.facility. For 2010,2011, the North region is expected to receive approximately 69%58% of the anticipated capital program, with the remaining 31%42% dedicated to the South region. In 2010,2011, we plan to spend approximately $585$600 million on capital and exploration activities.

Our proved reserves totaled approximately 2,0602,701 Bcfe at December 31, 2009,2010, of which 98% were natural gas. This reserve level was up by 6%31% from 1,9422,060 Bcfe at December 31, 20082009 on the strength of results from our drilling program. In 20092010, 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 200.1182.7 Bcfe primarily due to (i) downward revisions of 101.6(115.1 Bcfe due to lower 2009 oilin the North region and natural gas prices compared to 2008 and (ii) downward revisions of 120.467.6 Bcfe due toin the removalSouth region) of proved undeveloped reserves scheduled forthat are no longer in our five-year development beyond five years primarily due to the application of the Securities and Exchange Commission’s (SEC) new oil and gas reserve calculation methodology, partially offset by 21.9 Bcfe of positive performance revisions.plan.

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The following table presents certain reserve, production and well information as of December 31, 2009.2010.

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 2.92.3 million gross acres. In addition, we own fee interest in approximately 0.2 million gross acres, primarily in West Virginia. Our two largest fields, Brachfield Southeast in east Texas and Dimock in Susquehanna County, Pennsylvania, each containfield (Dimock), which is our only field that contains more than 15% of our proved reserves. In addition, we are focusing significant

Index to Financial Statements

drilling and production activityreserves, is located in the Angienortheast Pennsylvania. This field area of east Texas. These three fields combined makemakes up approximately 43%46% of our proved reserves.

The following table presents certain information with respect to our principal properties as of and for the year ended December 31, 2009.Dimock field:

NORTH REGION

The North region is comprised of the Appalachian and Rocky Mountains areas. In April 2009, we sold substantially all of our Canadian properties to a private Canadian company. 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 and the Paradox Basin in Colorado.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 20092010 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 expenditures, compared to $483.7 million for 2008, or 32% of our total 2008 capital and exploration

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expenditures. This decreaseincrease in spending was substantially driven by a $69.5 million decreasean expanded Marcellus horizontal drilling program in drilling and facilities costs year-over-year and the sale of our Canadian properties in April 2009.northeast Pennsylvania to hold acreage. For 2010,2011, we have budgeted approximately $402$350.0 million for capital and exploration expenditures in the region.

At December 31, 2009,2010, we had 4,1414,185 wells (3,536.9(3,588.5 net), of which 3,6813,724 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 950 to 9,0807,800 feet, with an average depth of approximately 3,9504,050 feet. In the Rocky Mountains area, principal producing intervals are in the Almond, Frontier Dakota and Honaker TrailDakota formations at depths ranging from 4,2008,100 to 14,375 feet, with an average depth of approximately 10,95011,050 feet. Average net daily

Natural gas production and reserves in 2009 for the North region was 136.6 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2009 was 49.2 Bcf and 125 Mbbls, respectively.

While natural gas production volumes from North region reservoirs are on balance lower on a per-well basis compared to other areas ofprimarily associated with the United States, the productive life of North region reserves is relatively long.Marcellus shale. At December 31, 2009,2010, we had 1,346.12,007.2 Bcfe of proved reserves (substantially all natural gas) in the North region, constituting 65%74% of our total proved reserves. Developed and undeveloped reserves made up 850.01,251.3 Bcfe and 496.1755.9 Bcfe of the total proved reserves for the North region, respectively.

In 2009,2010, we drilled 6263 wells (59.4(61.3 net) in the North region, of which 6162 wells (59.3(60.3 net) were development and extension wells. In 2010,2011, we plan to drill approximately 10054 wells (100(54.0 net), primarily in the Dimock field in northernnortheast Pennsylvania.

In 2009,2010, we produced and marketed approximately 321221.8 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.

Index to Financial Statements

Ancillary to our exploration, development and production operations, we operated a number of gas gathering and transmission pipeline systems, made up of approximately 3,1653,148 miles of pipeline with interconnects to three interstate transmission systems and seven local distribution companies and numerous end users as of the end of 2009.2010. 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 61%42% of our natural gas sales volume in the North region is sold at index-based prices under contracts with terms of one to three years. In addition, spotyear 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. Approximately one percent of North region production is sold on fixed price contracts that typically renew annually.

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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 Oklahoma and north Louisiana.Oklahoma. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley, Haynesville, PettitBossier, and James Lime formations in north Louisiana and 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 1,300approximately 2,500 to 16,97017,700 feet, with an average depth of approximately 8,7508,950 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, compared to $1,022.3 million for 2008, or 68% of our total 2008 capital and exploration expenditures. This decreaseincrease in capital spending is primarily due to $604.0 million paid in 2008 for the east Texas acquisition andlease acquisitions to establish a decrease of $176.9 million in total drilling. Of the total company year-over-year decrease in capital and exploration expenditures, approximately 93% was attributable to the decreasegreater position in the South region spending.oil window of the Eagle Ford shale. For 2010,2011, we have budgeted approximately $181$250 million for capital and exploration expenditures in the region. Our 20102011 South region drilling program will emphasize activity primarily in eastthe Eagle Ford shale in south Texas.

We had 1,7531,769 wells (1,230.2(1,231.1 net) in the South region as of December 31, 2009,2010, of which 1,3421,345 wells are operated by us. Average daily production in 20092010 was 145.5134.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 20092010 was 48.844.5 Bcf and 720759 Mbbls, respectively.

Index to Financial Statements

At December 31, 2009,2010, we had 713.8693.9 Bcfe of proved reserves (95%(93% natural gas) in the South region, which represented 35%26% of our total proved reserves. Developed and undeveloped reserves made up 474.7472.9 Bcfe and 239.1221.0 Bcfe of the total proved reserves for the South region, respectively.

In 2009,2010, we drilled 8150 wells (59.2(25.8 net) in the South region, of which 7547 wells (55.3(23.3 net) were development and extension wells. In 2010,2011, we plan to drill 3656 wells (24(29.1 net), primarily in east Texas, including the Minden and Angie fields.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 89%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 11%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 2009,2010, we produced and marketed approximately 1,966122.0 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 20092010 we employed natural gas and crude oil price collar and swap agreements for portions of our 2009 through 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 entered intoalso have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting. In 20082009 and 2007,2008, 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 2009, collars2010, swaps covered 48%29% of natural gas production and had a weighted-average floor of $9.40 per Mcf and a weighted-average ceiling of $12.39 per Mcf. For 2009, swaps covered 16% of natural gas production and 45%90% of crude oil production and had a weighted-average price of $12.18$9.30 per Mcf and $125.25$104.25 per Bbl, respectively.

As of December 31, 2009,2010, we had the following outstanding commodity derivatives:

Our decision to hedge 2010 and 2012 production fits with our risk management strategy and allows us to lock in the benefit of high commodity prices on a portion of our anticipated production.

Index to Financial Statements

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, 2009.2010.

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 12, 2010,1, 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 2009.2010. 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 estimateestimation process and provides oversight for the annual reviewaudit of 100% our year-end reserves by our independent third party engineers, Miller and Lents, Ltd. The management of ourOur corporate reservoir engineering group consists of threetwo petroleum/chemical engineers, with petroleum/chemical engineering degrees and between 1011 and 2728 years of industry experience, between 3four and 2728 years of reservoir engineering/management experience, and between 0.5three and 1112 years managing our reserves. AllBoth are members of the Society of Petroleum Engineers.

Index to Financial Statements

Qualifications of Third Party Engineers

The technical person primarily responsible for reviewaudit 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, 2009,2010, we had 735.2976.9 Bcfe of proved undeveloped reserves. During 2009, we converted 70.7reserves, which represents an increase of 241.7 Bcfe of reserves from proved undeveloped to proved developed. An additional 9.6 Bcfe of reserves associatedcompared with seven wells drilled in 2009 remain proved undeveloped as a result of the additional capital required to complete the wells. During 2009,December 31, 2009. For 2010, total capital related to the development of proved undeveloped reserves was $102.6 million. We$183.4 million, resulting in the conversion of 216.9 Bcfe of reserves to proved developed. During 2010, we had a downward revision391.8 Bcfe of total proved reservesundeveloped reserve additions and 249.5 Bcfe of 200.1positive proved undeveloped reserve performance revisions, primarily in the Dimock field in northeast Pennsylvania. Lastly, we removed 182.7 Bcfe primarily due to (i) downward revisions of 101.6(115.1 Bcfe due to lower 2009 oilin the North region and natural gas prices compared to 2008 and (ii) downward revisions of 120.467.6 Bcfe due toin the removalSouth region) of proved undeveloped reserves scheduled for development beyond five years primarily dueassociated with drilling locations no longer anticipated to the application of the SEC’s new oil and gas reserve calculation methodology, partially offset by 21.9 Bcfe of positive performance revisions. In accordance with the new rules we priced proved oil and gas reserves 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 monthbe developed within the 12-month period prior to the end of the reporting period.

As of December 31, 2009 we have 15.9 Bcfe of proved undeveloped reserves, representing less than 1% of our total proved reserves, that will require more thannext five years to develop due to coal mining operations or delays associated with an environment impact statement required to drill on federal land in Wyoming. An environmental impact study on federal land represents 1.9 Bcfe and the following table summarizes the reserves impacted by mining operations in West Virginia.years.

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Index to Financial Statements

Historical Reserves

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

Index to Financial Statements

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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.

Index to Financial Statements

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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, 2009.2010. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

Total Net Leasehold Acreage by Region of Operation

Index to Financial Statements

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, 2009.2010. The figures below assume no future successful development or renewal of undeveloped acreage.

Well Summary

The following table presents our ownership at December 31, 2009, in productive natural gas and oil wells in the Northby region (consisting primarily of various fields located in West Virginia, Pennsylvania, Colorado, Utah and Wyoming) and in the South region (consisting primarily of various fields located in Louisiana, Texas, Oklahoma and Kansas) .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.

Index to Financial Statements