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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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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, 2012

Commission file number 1-10447

CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)

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

Three Memorial City Plaza 840 Gessner Road, Suite 1400 Houston, Texas 77024
(Address of principal executive offices including ZIP code)

(281) 589-4600
(Registrant's telephone number, including area code)

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

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

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

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

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 o No ý

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

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

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 o.

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

Large accelerated filer ý |  | Accelerated filer o |  | Non-accelerated filer o (Do not check if a smaller reporting company) |  | Smaller reporting company o

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

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, 2012) was approximately $8.3 billion.

As of February 15, 2013, there were 210,429,889 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 2, 2013 are incorporated by reference into Part III of this report.

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TABLE OF CONTENTS

|  |  |  | PAGE |
--- | --- | --- | --- | --- | ---
PART I |  |  |  |  |  |
ITEMS 1 and 2 |  | Business and Properties |  |  | 6 |
ITEM 1A |  | Risk Factors |  |  | 21 |
ITEM 1B |  | Unresolved Staff Comments |  |  | 33 |
ITEM 3 |  | Legal Proceedings |  |  | 33 |
ITEM 4 |  | Mine Safety Disclosures |  |  | 33 |
|  | Executive Officers of the Registrant |  |  | 34 |
PART II |  |  |  |  |  |
ITEM 5 |  | Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  |  | 35 |
ITEM 6 |  | Selected Financial Data |  |  | 37 |
ITEM 7 |  | Management's Discussion and Analysis of Financial Condition and Results of Operations |  |  | 38 |
ITEM 7A |  | Quantitative and Qualitative Disclosures about Market Risk |  |  | 54 |
ITEM 8 |  | Financial Statements and Supplementary Data |  |  | 57 |
ITEM 9 |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |  |  | 112 |
ITEM 9A |  | Controls and Procedures |  |  | 112 |
ITEM 9B |  | Other Information |  |  | 112 |
PART III |  |  |  |  |  |
ITEM 10 |  | Directors, Executive Officers and Corporate Governance |  |  | 113 |
ITEM 11 |  | Executive Compensation |  |  | 113 |
ITEM 12 |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |  |  | 113 |
ITEM 13 |  | Certain Relationships and Related Transactions, and Director Independence |  |  | 113 |
ITEM 14 |  | Principal Accounting Fees and Services |  |  | 113 |
PART IV |  |  |  |  |  |
ITEM 15 |  | Exhibits, Financial Statement Schedules |  |  | 113 |

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FORWARD-LOOKING INFORMATION

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. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas and crude oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission filings. See "Risk Factors" in Item 1A for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

GLOSSARY OF CERTAIN OIL AND GAS TERMS

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

Abbreviations

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

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet of natural gas equivalent.

Btu. One British thermal unit.

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 or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

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

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

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

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

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

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

Oil. Crude oil and condensate.

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

Play. A geographic area with potential oil and gas reserves.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities, which become part of the cost of oil and gas produced.

Proved properties. Properties with proved reserves.

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. The project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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.

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

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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.

Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

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 landowners' 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.

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud.

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 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.

Unconventional play. A term used in the oil and gas industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds or (3) shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to achieve economic flow rates.

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 are 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.

Unproved properties. Properties with no proved reserves.

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.

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PART I

ITEMS 1 and 2. BUSINESS AND PROPERTIES

Cabot Oil & Gas Corporation is an independent oil and gas company engaged in the development, exploitation and exploration of oil and gas properties. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. We operate in one segment, natural gas and oil development, exploitation and exploration, exclusively in the continental United States. We have regional offices located in Houston, Texas and Pittsburgh, Pennsylvania.

STRATEGY

Our objective is to enhance shareholder value over the long-term through consistent growth in cash flows, earnings, production and reserves. We believe this is attainable through a combination of disciplined management and our core asset base that offers a strategic advantage for continued growth. Key components of our business strategy include:

Disciplined Capital Spending Focused on High-Return, Organic Projects. We allocate our capital program based on projects that we expect will enable us to maximize our production and reserve growth at attractive returns. Our capital program is based on the expectation of being fully funded through operating cash flows. While we consider various growth opportunities, including strategic acquisitions, our primary focus is organic growth through drilling our core areas of operation where we believe we can exploit our extensive inventory of low-cost, high-return repeatable drilling opportunities.

Low Cost Structure. Our operations are focused on select unconventional plays with significant resource potential that allow us to add and produce reserves at a low cost. We have developed sizable, contiguous acreage positions in these core operating areas and believe the concentration of our assets allows us to further reduce costs through economies of scale. Furthermore, since we operate in a limited number of geographic areas, we believe we can leverage our technical expertise in these areas to achieve further cost reductions through operational efficiencies. We also operate a majority of our properties, which allows us to more effectively manage all elements of our cost structure.

Conservative Financial Position and Financial Flexibility. We believe the prudent management of our balance sheet and the active management of commodity price risk allows us the financial flexibility to continue to provide consistent production and reserve growth over time, even in periods of depressed commodity prices. We utilize derivative contracts to manage commodity price risk and to provide a level of cash flow predictability. In the event we experience a lower than anticipated commodity price environment, we believe that we have the flexibility to supplement the funding of our capital program with asset sales, joint ventures and borrowings under our credit facility.

Expand our Unconventional Resource Initiatives Through Value Generating Opportunities. We will continue to evaluate opportunities that generate value and contribute to our growth initiatives, including potential strategic sales of assets that no longer fit in our current portfolio and the use of various joint venture arrangements to achieve our objectives. We intend to reinvest the proceeds from these activities in our core unconventional assets.

2013 OUTLOOK

In 2013, we plan to spend between approximately $950.0 million and $1.0 billion on capital and exploration activities. We plan to drill approximately 170 to 180 gross wells (or 130 to 145 net), focusing our capital program in the Marcellus Shale in northeast Pennsylvania, the Eagle Ford and Pearsall Shale in south Texas and the Marmaton oil play in Oklahoma. We expect to allocate approximately 65% of our 2013 capital program to the Marcellus Shale, approximately 30% to our

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liquids-focused plays in south Texas and Oklahoma and the remaining 5% to other emerging plays and non-drilling expenditures. In 2013, we also expect to contribute approximately $12.0 million to Constitution Pipeline Company, LLC (Constitution) to fund costs associated with the development and construction of a pipeline in northeast Pennsylvania, which is incremental to our capital and exploration expenditures. See Note 5 of the Notes to the Consolidated Financial Statements for further details regarding our investment in Constitution.

DESCRIPTION OF PROPERTIES

Our exploration, development and production operations are primarily concentrated in three unconventional plays—the Marcellus Shale in Pennsylvania, the Eagle Ford in south Texas and the Marmaton oil play in Oklahoma. We also have significant non-core operations in various other unconventional and conventional plays throughout the continental United States.

Marcellus Shale

The Marcellus Shale is one of our major operating areas and represents our largest growth and capital investment area over the last four years. Our properties are principally located in Susquehanna County and to a lesser extent Bradford and Wyoming Counties, Pennsylvania. We currently hold approximately 200,000 net acres in the dry gas window of the play. Our 2012 net production in the Marcellus Shale was 209.3 Bcfe, representing approximately 78% of our total equivalent production for the year. As of December 31, 2012, we had a total of 224.2 net wells producing in the Marcellus Shale.

During 2012, we invested $616.6 million in the Marcellus Shale and drilled 69.7 net horizontal wells and completed and turned in line 80.2 net wells. As of December 31, 2012, we had 32.0 net wells that were either in the completion stage or waiting on completion or connection to a pipeline. We exited 2012 with five drilling rigs operating in the play.

Eagle Ford Shale

Our properties in the Eagle Ford Shale are principally located in Atascosa, Frio, La Salle and Zavala Counties, Texas where we hold over 60,000 net acres in the oil window of the play. In 2012, our net liquids and natural gas production from the Eagle Ford was 1,581 Mbbl and 1.6 Bcf, respectively, or 11.1 Bcfe, representing approximately 4% of our full year equivalent production. As of December 31, 2012, we had a total of 47.7 net wells producing in the Eagle Ford.

During 2012, we invested $171.0 million in the Eagle Ford and drilled or participated in drilling 23.2 net wells. We exited 2012 with one drilling rig operating in the play.

Marmaton

Our properties in the Marmaton oil play are principally located in Beaver County, Oklahoma and Ochiltree County, Texas. As of December 31, 2012, we had over 70,000 net acres in the play. In 2012, our net liquids and natural gas production from the Marmaton was 364 Mbbl and 0.6 Bcf, respectively, or 2.8 Bcfe, representing approximately 1% of our total equivalent production for the year. As of December 31, 2012, we had a total of 21.1 net wells producing in the Marmaton and 3.3 net wells completing or waiting on completion.

During 2012, we invested $80.3 million in the Marmaton and drilled or participated in drilling 17.9 net wells. We exited 2012 with two drilling rigs operating in the play.

Other Oil and Gas Properties

In addition to our core unconventional resource plays, we also operate or participate in other conventional and unconventional plays throughout the continental United States, including the Pearsall

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Shale in south Texas, the Utica Shale in Pennsylvania; the Cotton Valley, Haynesville, Bossier, and James Lime formations in east Texas; the Devonian Shale, Big Lime, Weir and Berea Shale in West Virginia; the Frio, Vicksburg and Wilcox formations in south Texas; and the Chase, Morrow and Chester formations in Oklahoma.

In 2013, we plan to drill a total of 9.8 net wells in the Pearsall Shale, all of which are subject to a joint development agreement with a wholly owned subsidiary of Osaka Gas Co., Ltd. (Osaka) that was entered into contemporaneously with the sale of a 35% non-operated working interest associated with certain of our Pearsall Shale undeveloped leaseholds in June 2012. Under the joint development agreement, Osaka agreed to fund 85% of our share of future drilling and completion costs associated with these leaseholds until it has paid approximately $126.0 million. The drilling and completion carry will terminate in June 2014.

Other Properties

Ancillary to our exploration, development and production operations, we operate a number of gas gathering and transmission pipeline systems, made up of approximately 3,134 miles of pipeline with interconnects to three interstate transmission systems and five local distribution companies and numerous end users as of the end of 2012. The majority of our pipeline infrastructure is located in West Virginia and 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 also 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 typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The pipeline systems and storage fields are fully integrated with our operations in West Virginia.

DIVESTITURES

In December 2012, we sold certain proved oil and gas properties located in south Texas to a private company for $29.9 million, subject to post closing adjustments, and recognized an $18.2 million loss on sale of assets.

In June 2012, we sold a 35% non-operated working interest associated with certain of our Pearsall Shale undeveloped leaseholds in south Texas to a wholly-owned subsidiary of Osaka for $125.0 million in cash proceeds and recognized a $67.0 million gain on sale of assets.

In 2012, we sold various other unproved properties and other assets for total proceeds of $14.4 million and recognized an aggregate gain of $1.8 million.

In October 2011, we sold certain proved oil and gas properties located in Colorado, Utah and Wyoming to Breitburn Energy Partners, L.P. for $285.0 million. We received $283.2 million in cash proceeds, after closing adjustments, and recognized a $4.2 million gain on sale of assets.

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In May 2011, we sold certain of our unproved Haynesville and Bossier Shale oil and gas properties in east Texas to a third party. We received approximately $47.0 million in cash proceeds and recognized a $34.2 million gain on sale of assets.

In 2011, we sold various other unproved properties and other assets for total proceeds of $73.5 million and recognized an aggregate gain of $25.0 million.

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.

In 2010, we sold various other proved and unproved properties and other assets for total proceeds of $32.2 million and recognized an aggregate gain of $16.3 million.

MARKETING

The principal markets for our natural gas are in the northeastern and midwestern United States and the industrialized Gulf Coast area. In the northeastern United States, we sell natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system. In the Gulf Coast area and the midwestern United States, we sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Properties in the Gulf Coast area are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.

RISK MANAGEMENT

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risk associated with our production. While there are many different types of derivatives available, we generally utilize collar and swap agreements to attempt to manage price risk more effectively. The collar arrangements are a combination of put and call options used to establish floor and ceiling prices for a fixed volume of natural gas and crude oil 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 swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for that period when the swap was put in place.

During 2012, natural gas and crude oil swaps covered 96.0 Bcf, or 38%, and 1,709 Mbbl, or 76%, of natural gas and crude oil production at an average price of $5.22 per Mcf and $100.12 per Bbl, respectively. Natural gas basis swaps covered 17 Bcf, or 7%, of our natural gas production at an average price of $(0.25) per Mcf. Natural gas collars with a floor price of $3.60 per Mcf and a ceiling price of $4.17 per Mcf covered 3.0 Bcf, or 1%, of our natural gas production at an average price of $3.70 per Mcf.

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As of December 31, 2012, we had the following outstanding commodity derivatives:

Commodity and Derivative Type |  | Weighted-Average Contract Price |  | Volume |  | Contract Period |
--- | --- | --- | --- | --- | --- | --- | ---
Natural gas collars |  | $3.09 Floor / $4.12 Ceiling per Mcf |  |  | 35.5 Bcf |  |  | Jan. 2013 - Dec. 2013 |
Natural gas collars |  | $3.35 Floor / $4.01 Ceiling per Mcf |  |  | 35.5 Bcf |  |  | Jan. 2013 - Dec. 2013 |
Natural gas collars |  | $3.40 Floor / $4.12 Ceiling per Mcf |  |  | 17.7 Bcf |  |  | Jan. 2013 - Dec. 2013 |
Natural gas collars |  | $3.60 Floor / $4.17 Ceiling per Mcf |  |  | 17.7 Bcf |  |  | Jan. 2013 - Dec. 2013 |
Natural gas collars |  | $3.76 Floor / $4.16 Ceiling per Mcf |  |  | 17.7 Bcf |  |  | Jan. 2013 - Dec. 2013 |
Natural gas collars |  | $3.86 Floor / $4.34 Ceiling per Mcf |  |  | 17.7 Bcf |  |  | Jan. 2013 - Dec. 2013 |
Natural gas collars |  | $5.15 Floor / $6.20 Ceiling per Mcf |  |  | 17.7 Bcf |  |  | Jan. 2013 - Dec. 2013 |
Crude oil swaps |  | $101.90 per Bbl |  |  | 1,095 Mbbl |  |  | Jan. 2013 - Dec. 2013 |

We will continue to evaluate the benefit of using 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

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

|  | December 31, |
--- | --- | --- | ---
|  | 2012 |  | 2011 |  | 2010 |
Natural Gas (Bcf) |  |  |  |  |  |  |  |  |  |
Proved developed reserves |  |  | 2,216 |  |  | 1,734 |  |  | 1,681 |
Proved undeveloped reserves(1) |  |  | 1,480 |  |  | 1,176 |  |  | 963 |
|  |  | 3,696 |  |  | 2,910 |  |  | 2,644 |
Crude Oil & Liquids (Mbbl) |  |  |  |  |  |  |  |  |  |
Proved developed reserves |  |  | 12,828 |  |  | 10,922 |  |  | 7,129 |
Proved undeveloped reserves(1) |  |  | 11,546 |  |  | 9,548 |  |  | 2,362 |
|  |  | 24,374 |  |  | 20,470 |  |  | 9,491 |
Natural gas equivalent (Bcfe)(2) |  |  | 3,842 |  |  | 3,033 |  |  | 2,701 |
Reserve life (in years)(3) |  |  | 14.4 |  |  | 16.2 |  |  | 20.7 |

(1)
  Proved undeveloped reserves for 2012 and 2011 include reserves drilled but awaiting completion of 153.3 Bcfe and 132.4 Bcfe, respectively. There were no reserves drilled awaiting completion included in proved undeveloped reserves in 2010.
(2)
  Natural gas equivalents are determined using a ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.
(3)
  Reserve life index is equal to year-end reserves divided by annual production for the year ended December 31, 2012, 2011 and 2010, respectively.

Our proved reserves totaled approximately 3,842 Bcfe at December 31, 2012, of which 96% were natural gas. This reserve level was up by 27% from 3,033 Bcfe at December 31, 2011 due to the positive results from our drilling program. In 2012, we had a net upward revision of 188.6 Bcfe, which was primarily due to an upward performance revision of 369.6 Bcfe, primarily in the Dimock field in northeast Pennsylvania, partially offset by a downward revision of 114.5 Bcfe associated with decreased reserve commodity pricing and a downward revision of 66.5 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.

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Our reserve estimates were based on decline curve extrapolations, material balance calculations, volumetric calculations, analogies, or combinations of these methods for each well, reservoir or field. The proved reserve estimates presented herein were prepared by our petroleum engineering staff and audited by Miller and Lents, Ltd. (Miller and Lents), independent petroleum engineers. Miller and Lents made independent estimates for 100% of the proved reserves estimated by us and concluded, in their judgment we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues. Further, Miller and Lents has concluded (1) the reserves estimation methods employed by us were appropriate, and our classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) our reserves estimation processes were comprehensive and of sufficient depth, (3) the data upon which we relied were adequate and of sufficient quality, and (4) the results of our estimates and projections are, in the aggregate, reasonable. A copy of the audit letter by Miller and Lents dated January 31, 2013, has been filed as an exhibit to this Form 10-K.

Our reserves are sensitive to natural gas and crude oil prices and their effect on the economic productive life of producing properties. Our reserves are based on 12-month average crude oil and natural gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during 2012, 2011 and 2010, respectively. 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.

For additional information regarding estimates of proved reserves, the audit of such estimates by Miller and Lents and other information about our reserves, including the risks inherent in our estimates of proved reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 and "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.

Internal Control

Our corporate reservoir engineers report to the Vice President of Engineering and Technology, 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. Our corporate reservoir engineering group consists of four petroleum/chemical engineers, with petroleum/chemical engineering degrees and between two and 30 years of industry experience, between two and 30 years of reservoir engineering/management experience, and between two and 14 years managing our reserves. All four engineers are members of the Society of Petroleum Engineers.

Qualifications of Third Party Engineers

The technical person primarily responsible for the audit of our reserve estimates at Miller and Lents 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 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.

Proved Undeveloped Reserves

At December 31, 2012 we had 1,549 Bcfe of proved undeveloped reserves with future development costs of $1.3 billion, which represents an increase of 316.1 Bcfe compared with December 31, 2011. For

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2012, total capital related to the development of proved undeveloped reserves was $370.7 million, resulting in the conversion of 410.9 Bcfe of reserves to proved developed. During 2012, we had 501.4 Bcfe of proved undeveloped reserve additions and 233.5 Bcfe of positive proved undeveloped reserve performance revisions, primarily in the Dimock field in northeast Pennsylvania. These increases were partially offset by the removal of 66.5 Bcfe of proved undeveloped reserves associated with drilling locations in east Texas no longer anticipated to be developed within the next five years due to a continued shift in our drilling program.

PRODUCTION, SALES PRICE AND PRODUCTION COSTS

The following table presents historical information about our production volumes for natural gas and crude oil (including condensate and natural gas liquids), average natural gas and crude oil sales prices, and average production costs per equivalent, including our Dimock field located in northeast Pennsylvania, which contains more than 15% of our total proved reserves.

|  | Year Ended December 31, |
--- | --- | --- | ---
|  | 2012 |  | 2011 |  | 2010 |
Production Volumes |  |  |  |  |  |  |  |  |  |
Natural Gas (Bcf) |  |  |  |  |  |  |  |  |  |
Dimock field |  |  | 209.3 |  |  | 119.3 |  |  | 49.5 |
Total |  |  | 253.2 |  |  | 178.8 |  |  | 125.5 |
Crude Oil/Condensate/NGL (Mbbl) |  |  |  |  |  |  |  |  |  |
Total |  |  | 2,407 |  |  | 1,443 |  |  | 859 |
Equivalents (Bcfe) |  |  |  |  |  |  |  |  |  |
Dimock field |  |  | 209.3 |  |  | 119.3 |  |  | 49.5 |
Total |  |  | 267.7 |  |  | 187.5 |  |  | 130.7 |
Natural Gas Average Sales Price ($/Mcf) |  |  |  |  |  |  |  |  |  |
Dimock field |  | $ | 2.82 |  | $ | 3.85 |  | $ | 4.48 |
Total (excluding realized impact of derivative settlements) |  | $ | 2.79 |  | $ | 3.99 |  | $ | 4.46 |
Total (including realized impact of derivative settlements) |  | $ | 3.67 |  | $ | 4.46 |  | $ | 5.69 |
Crude Oil Average Sales Price ($/Bbl) |  |  |  |  |  |  |  |  |  |
Total (excluding realized impact of derivative settlements) |  | $ | 96.65 |  | $ | 89.48 |  | $ | 75.60 |
Total (including realized impact of derivative settlements) |  | $ | 101.65 |  | $ | 90.49 |  | $ | 97.91 |
Average Production Costs ($/Mcfe) |  |  |  |  |  |  |  |  |  |
Dimock field |  | $ | 0.08 |  | $ | 0.09 |  | $ | 0.09 |
Total |  | $ | 0.37 |  | $ | 0.47 |  | $ | 0.89 |

ACREAGE

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 10 years. These properties are held for longer periods if production is established.

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The following table summarizes our gross and net developed and undeveloped leasehold and mineral fee acreage at December 31, 2012. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.

|  | Developed |  | Undeveloped |  | Total |
--- | --- | --- | --- | --- | --- | --- | ---
|  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |
Leasehold acreage |  |  | 1,161,314 |  |  | 975,508 |  |  | 838,524 |  |  | 675,746 |  |  | 1,999,838 |  |  | 1,651,254 |
Mineral fee acreage |  |  | 133,623 |  |  | 112,570 |  |  | 61,744 |  |  | 52,242 |  |  | 195,367 |  |  | 164,812 |
Total |  |  | 1,294,937 |  |  | 1,088,078 |  |  | 900,268 |  |  | 727,988 |  |  | 2,195,205 |  |  | 1,816,066 |

Total Net Undeveloped Acreage Expiration

Our net undeveloped acreage expiring over the next three years as of December 31, 2012 is 202,375, 95,310 and 82,660 for the years ending December 31, 2013, 2014 and 2015, respectively. These amounts assume no future successful development, extension or renewal of undeveloped acreage.

WELL SUMMARY

The following table presents our ownership in productive natural gas and crude oil wells at December 31, 2012. This summary includes natural gas and crude oil wells in which we have a working interest.

|  | Gross |  | Net |
--- | --- | --- | --- | --- | ---
Natural Gas |  |  | 4,998 |  |  | 4,300.9 |
Crude Oil |  |  | 286 |  |  | 209.2 |
Total(1) |  |  | 5,284 |  |  | 4,510.1 |

(1)
  Total percentage of gross operated wells is 88.3%.

DRILLING ACTIVITY

We drilled wells or participated in the drilling of wells as indicated in the table below.

|  | Year Ended December 31, |
--- | --- | --- | ---
|  | 2012 |  | 2011 |  | 2010 |
|  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |
Development Wells |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Productive |  |  | 149 |  |  | 102.7 |  |  | 149 |  |  | 86.0 |  |  | 96 |  |  | 74.3 |
Dry |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1 |  |  | 1.0 |
Extension Wells |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Productive |  |  | 8 |  |  | 7.0 |  |  | 7 |  |  | 5.5 |  |  | 12 |  |  | 8.3 |
Dry |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Exploratory Wells |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Productive |  |  | 9 |  |  | 6.3 |  |  | 4 |  |  | 3.5 |  |  | 3 |  |  | 2.5 |
Dry |  |  | 4 |  |  | 1.8 |  |  | 1 |  |  | 1.0 |  |  | 1 |  |  | 1.0 |
Total |  |  | 170 |  |  | 117.8 |  |  | 161 |  |  | 96.0 |  |  | 113 |  |  | 87.1 |

At December 31, 2012, 18 wells (13.1 net) were being drilled or awaiting completion.

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OTHER BUSINESS MATTERS

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes or development obligations under oil and gas leases. As is customary in the industry in the case of undeveloped properties, often little investigation of record title is made at the time of lease acquisition. Investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

Competition

Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times and distribution efficiencies, affect competition. We believe that our extensive acreage position and our access to gathering and pipeline infrastructure in Pennsylvania, along with services and equipment that we have secured for the upcoming years, enhance our competitive position over other producers who do not have similar systems or services in place. We also actively compete against other companies with substantial financial and other resources.

Major Customers

In 2012, three customers accounted for approximately 18%, 12% and 10%, respectively, of our total sales. In 2011, we did not have any one customer account for greater than 10% of our total sales. In 2010, one customer accounted for approximately 11% of our total sales. We do not believe that the loss of any of these customers would have a material adverse effect on us because alternative customers are readily available.

Seasonality

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

Regulation of Oil and Natural Gas Exploration and Production

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil

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and gas industry increases its cost of doing business and, consequently, affects its profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.

Natural Gas Marketing, Gathering and Transportation

Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 (NGPA), and the regulations promulgated under those statutes, the FERC regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective beginning in January 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all "first sales" of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC granted to all producers such as us a "blanket certificate of public convenience and necessity" authorizing the sale of natural gas for resale without further FERC approvals. As a result of this policy, all of our produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005 (2005 Act), the NGA was amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established regulations intended to increase natural gas pricing transparency by, among other things, requiring market participants to report their gas sales transactions annually to the FERC. The 2005 Act also significantly increased the penalties for violations of the NGA and the FERC's regulations up to $1,000,000 per day per violation. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties and procedure under its enforcement program.

Some of our pipelines are subject to regulation by the FERC. We indirectly own an intrastate natural gas pipeline that provides interstate transportation and storage services pursuant to Section 311 of the NGPA, as well as intrastate transportation and storage services that are regulated by the West Virginia Public Service Commission. For qualified intrastate pipelines, FERC allows interstate transportation service "on behalf of" interstate pipelines or local distribution companies served by interstate pipelines without subjecting the intrastate pipeline to the more comprehensive NGA jurisdiction of the FERC. We provide Section 311 service in accordance with a publicly available Statement of Operating Conditions filed with FERC under rates that are subject to approval by the FERC. On December 26, 2012, we filed with the FERC a petition for rate approval of our existing interstate transportation rates and a proposed decrease of our storage rates. In addition, we have executed a precedent agreement with Constitution Pipeline Company, LLC, a subsidiary of Williams Partners L.P., for transportation capacity and a 25% equity interest in a pipeline to be constructed in the states of New York and Pennsylvania. In April 2012, the project sponsors requested to participate in FERC's pre-filing procedures and, once complete, will need to request and receive a certificate of public convenience and necessity from FERC prior to commencing construction. There is no guarantee that FERC will certify the project or, if they do, that the project scope or timeline for construction will remain unchanged by the regulatory permitting process. If placed into service, the project pipeline will be an interstate pipeline subject to full regulation by FERC under the NGA.

Our production and gathering facilities are not subject to jurisdiction of the FERC; however, our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted a series of rulemakings that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, requiring interstate

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pipeline companies to separate their wholesale gas marketing business from their gas transportation business, and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other, and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.

In light of these statutory and regulatory changes, most pipelines have divested their natural gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants. Most pipelines have also implemented the large-scale divestiture of their natural gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines are required to provide unbundled, open and nondiscriminatory transportation and transportation-related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. As a result of FERC requiring natural gas pipeline companies to separate marketing and transportation services, sellers and buyers of natural gas have gained direct access to pipeline transportation services, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, we cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Further, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry will continue or what effect future policies will have on our sale of gas.

Federal Regulation of Petroleum

Our sales of oil and natural gas liquids are not regulated and are made at market prices. However, the price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines, which are regulated by the FERC under the Interstate Commerce Act (ICA). FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service, and that such service not be unduly discriminatory or preferential.

Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which annual adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase or decrease the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2010, to implement this required five-year re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 2.65% should be the oil pricing index for the five-year period beginning July 1, 2011. The result of indexing is a "ceiling rate" for each rate, which is the maximum at which the pipeline may set its interstate transportation rates. A pipeline may also file cost-of-service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Rates are subject to challenge by protest when they are filed or changed. For indexed rates, complaints alleging that the rates are unjust and unreasonable may only be pursued if the complainant can show that a substantial change has occurred since the enactment of Energy Policy Act of 1992 in either the economic circumstances of the pipeline or in the nature of the services provided, that were a basis for

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the rate. There is no such limitation on complaints alleging that the pipeline's rates or terms and conditions of service are unduly discriminatory or preferential.

Another FERC matter that may impact our transportation costs relates to a policy that allows a pipeline structured as a master limited partnership or similar non-corporate entity to include in its rates a tax allowance with respect to income for which there is an "actual or potential income tax liability," to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest is required to file a tax return that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. We currently do not transport any of our crude oil or natural gas liquids on a pipeline structured as a master limited partnership.

We are unable to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or of the application of the FERC's policy on income tax allowances.

Pipeline Safety Regulation

Certain of our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation (DOT) and the West Virginia Public Service Commission. In 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (2002 Act), which contains a number of provisions intended to increase pipeline operating safety. The DOT's final regulations implementing the act became effective February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission and non-rural gathering pipeline facilities in certain locations within ten years, and at least every seven years thereafter. On March 15, 2006, the DOT revised these regulations to define more clearly the categories of gathering facilities subject to DOT regulation, establish new safety rules for certain gathering lines in rural areas, revise the current regulations applicable to safety and inspection of gathering lines in non-rural areas, and adopt new compliance deadlines. The initial baseline assessments under our integrity management program for our pipeline system in West Virginia were completed in January 2013. Pipeline integrity was confirmed at each of the targeted assessment sites. A new seven-year reassessment cycle will begin in 2013.

In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (PIPES Act), which reauthorized the programs adopted under the 2002 Act, proposed enhancements for state programs to reduce excavation damage to pipelines, established increased federal enforcement of one-call excavation programs, and established a new program for review of pipeline security plans and critical facility inspections. Pursuant to the PIPES Act, the DOT issued regulations on May 5, 2011 that would, with limited exceptions, subject all low-stress hazardous liquids pipelines, regardless of location or size, to the DOT's pipeline safety regulations.

In December 2011, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The act increased the maximum civil penalties for pipeline safety administrative enforcement actions; required the DOT to issue regulations requiring the use of automatic or remote-controlled shutoff valves on new and rebuilt pipelines and to study and report on the expansion of integrity management requirements, the sufficiency of existing gathering line regulations to ensure safety, and the use of leak detection systems by hazardous liquid pipelines; required pipeline operators to verify their records on maximum allowable operating pressure; and imposed new emergency response and incident notification requirements. The act reflects many of the areas of possible regulatory change described in an Advance Notice of Proposed Rulemaking issued by the DOT on August 18, 2011. Aside from rules contained in the act, which include revisions to DOT's civil penalty authority and the requirement that pipelines verify maximum allowable operating pressure, the DOT has not yet promulgated any new regulations required by the act.

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On December 3, 2009, the DOT adopted a regulation requiring gas and hazardous liquid pipelines that use supervisory control and data acquisition (SCADA) systems and have at least one controller and control room to develop written control room management procedures by August 1, 2011 and implement the procedures by February 1, 2013. The DOT expedited the program implementation deadline to October 1, 2011 for most of the requirements, except for certain provisions regarding adequate information and alarm management, which had a program implementation deadline of August 1, 2012. We developed and implemented the required control room management procedures in accordance with the deadlines. Effective January 1, 2011, natural gas and hazardous liquid pipelines also became subject to updated reporting requirements with DOT.

The cost of compliance with DOT's integrity management rules depends on integrity testing and the repairs found to be necessary by such testing. Changes to the amount of pipe subject to integrity management, whether by expansion of the definition of the type of areas subject to integrity management procedures or of the applicability of such procedures outside of those defined areas can have a significant impact on costs we may incur to ensure compliance. In the future other laws and regulations may be enacted or adopted or existing laws may be reinterpreted in a manner that could impact our compliance costs. In addition, we may be subject to DOT's enforcement actions and penalties for failure to comply with pipeline regulations.

Environmental and Safety Regulations

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

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

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

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

Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the "Superfund" law, and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the current and past owners and operators of a site where the release occurred and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA's definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.

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

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

Clean Air Act. Our operations are subject to the Federal Clean Air Act and comparable local and state laws and regulations to control emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control toxic air pollutants might require installation of additional controls. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.

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Hydraulic Fracturing. Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or natural gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Such efforts could have an adverse effect on oil and natural gas production activities. For additional information about hydraulic fracturing and related environmental matters, please read "Risk Factors—Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and operating restrictions or delays" in Item 1A.

Greenhouse Gas. In response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to global climate change, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases from sources within the United States between 2012 and 2050. In addition, almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The EPA has also begun to regulate carbon dioxide and other greenhouse gas emissions under existing provisions of the Clean Air Act. Please read "Risk Factors—Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce" in Item 1A.

OSHA and Other Laws and Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA), and comparable state laws. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.

Employees

As of December 31, 2012, we had 589 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement.

Website Access to Company Reports

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

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Corporate Governance Matters

Our Corporate Governance Guidelines, Corporate Bylaws, Code of Business Conduct, Audit Committee Charter, Corporate Governance and Nominations Committee Charter, Compensation Committee Charter and Safety and Environmental Affairs Committee Charter are available on our website at www.cabotog.com, under the "Governance" section of "About Cabot." Requests can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas, 77024.

ITEM 1A. RISK FACTORS

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

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results and could result in an impairment charge. See "Future natural gas and oil price declines may result in write-downs of the carrying amount of our assets, which could materially and adversely affect our results of operations." Because our reserves are predominantly natural gas, changes in natural gas prices have a more significant impact on our financial results.

Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:

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  the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas from shale (such as that produced from our Marcellus properties) on the global natural gas supply;
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  the level of consumer product demand;
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  weather conditions;
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  political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;
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  the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree to and maintain oil price and production controls;
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  the price level of foreign imports;
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  actions of governmental authorities;
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  the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;
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  inventory storage levels;
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  the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;
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  the price, availability and acceptance of alternative fuels;

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  technological advances affecting energy consumption;
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  speculation by investors in oil and gas;
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  variations between product prices at sales points and applicable index prices; and
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  overall economic conditions, including the value of the U.S. dollar relative to other major currencies.

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

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

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

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  unexpected drilling conditions, pressure or irregularities in formations;
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  equipment failures or accidents;
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  adverse weather conditions;
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  decreases in natural gas and oil prices;
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  surface access restrictions;
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  loss of title or other title related issues;
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  compliance with, or changes in, governmental requirements and regulation; and
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  costs of shortages or delays in the availability of drilling rigs or crews and the delivery of equipment and materials.

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

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  the results of exploration efforts and the acquisition, review and analysis of the seismic data;
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  the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;
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  the approval of the prospects by other participants after additional data has been compiled;
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  economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;
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  our financial resources and results; and

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  the availability of leases and permits on reasonable terms for the prospects and any delays in obtaining such permits.

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

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

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

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

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

Future natural gas and oil price declines may result in write-downs of the carrying amount of our assets, which could materially and adversely affect our results of operations.

The value of our assets depends on prices of natural gas and crude oil. Declines in these prices as well as increases in development costs, changes in well performance, delays in asset development or deterioration of drilling results may result in our having to make material downward adjustments to our estimated proved reserves, and could result in an impairment charge and a corresponding write-down of the carrying amount of our oil and natural gas properties.

We evaluate our oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate a property's carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future crude oil and natural gas prices, operating costs and anticipated production from proved reserves (also potentially including risk-adjusted probable and possible reserves from time to time), are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices

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adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices decline further, there could be a significant revision in the future.

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

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

Our reserve report estimates that production from our proved developed reserves as of December 31, 2012 will increase at an estimated rate of 9% during 2013 and then decline at estimated rates of 36%, 22% and 17% during 2014, 2015 and 2016, respectively. Future development of proved undeveloped and other reserves currently not classified as proved developed producing will impact these rates of decline. Because of higher initial decline rates from newly developed reserves, we consider this pattern fairly typical.

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

We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.

We rely upon access to both our revolving credit facility and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by the cash flow from operations or other sources. Future challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.

Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.

Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our business plan, we considered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 2013 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of

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our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2013 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, the oil spill in the Gulf of Mexico, and the explosion of natural gas transmission lines in California and elsewhere, may lead to increased regulatory scrutiny which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These action may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

Increased drilling in the shale formations may cause pipeline and gathering system capacity constraints that may limit our ability to sell natural gas and/or receive market prices for our natural gas.

The Marcellus Shale wells we have drilled to date have generally reported very high initial production rates. If drilling in the Marcellus Shale continues to be successful, the amount of natural gas being produced in the area from these new wells, as well as natural gas produced from other existing wells, may exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available. In such event, this could result in wells being shut in or awaiting a pipeline connection or capacity and/or natural gas being sold at much lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations and cash flows.

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

Our operations are subject to extensive federal, state and local laws and regulations, including drilling, permitting and safety laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities, and new laws and regulations or revisions or reinterpretations of existing laws and regulations could further increase these costs. Increased scrutiny of our industry may also occur as a result of EPA's 2011-2013 National Enforcement Initiative, "Assuring Energy Extraction Activities Comply with Environmental Laws," through which EPA will address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. For example, we could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to

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administrative, civil and criminal penalties as well as the imposition of corrective action orders. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.

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

Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration potential, future natural gas and oil prices, operating costs, production taxes and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise.

There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an "as is" basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.

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

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

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  the challenge of integrating the acquired properties while carrying on the ongoing operations of our business;
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  the inability to retain key employees of the acquired business;
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  potential lack of operating experience in a geographic market of the acquired properties; and
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  the possibility of faulty assumptions underlying our expectations.

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

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

Our business involves a variety of operating risks, including:

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  well site blowouts, cratering and explosions;
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  equipment failures;

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  pipe or cement failures and casing collapses, which can release natural gas, oil, drilling fluids or hydraulic fracturing fluids;
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  uncontrolled flows of natural gas, oil or well fluids;
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  pipeline ruptures;
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  fires;
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  formations with abnormal pressures;
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  handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids;
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  release of toxic gas;
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  buildup of naturally occurring radioactive materials;
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  pollution and other environmental risks, including conditions caused by previous owners or lessors of our properties; and
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  natural disasters.

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

Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. As of December 31, 2012, we owned or operated approximately 3,134 miles of natural gas gathering and pipeline systems. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe periodically require repair, replacement or additional maintenance.

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

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

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

Other companies operate some of the properties in which we have an interest. Non-operated wells represented approximately 11.7% of our total owned gross wells, or approximately 3.7% of our owned net wells, as of December 31, 2012. We have limited ability to influence or control the operation or future development of these non-operated properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

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

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

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

The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. We deliver our natural gas and oil production primarily through gathering systems and pipelines that we do not own. The lack of available of capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Third-party systems and facilities may be unavailable due to market conditions or mechanical or other reasons. To the extent these services are unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Our failure to obtain these services on acceptable terms could materially harm our business.

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

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

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

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risk associated with our natural gas and crude oil production. While there are many different types of derivatives available, we generally utilize collar and swap agreements to attempt to manage price risk more effectively.

The collar arrangements are put and call options used to establish floor and ceiling 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

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the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for that period when the swap is put in place. These hedging arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

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  a counterparty is unable to satisfy its obligations;
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  production is less than expected; or
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  there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

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

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

Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.

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

Most of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand or other proppants into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has released draft permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where EPA is the permitting authority, including Pennsylvania. As a result, we may be subject to additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. In addition, legislation introduced in Congress would provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids. Moreover, on November 23, 2011, the EPA announced that it was granting in part a petition to initiate a rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and gas exploration and production. Further, on May 4, 2012, the Department of the Interior's Bureau of Land Management ("BLM") issued a proposed rule to regulate hydraulic fracturing on public and Indian land. The rule would require companies to publicly disclose the chemicals used in hydraulic fracturing operations to the BLM after fracturing operations have been

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completed and includes provisions addressing well-bore integrity and flowback water management plans. We voluntarily disclose on a well-by-well basis the chemicals we use in the hydraulic fracturing process at www.fracfocus.org.

On August 16, 2012, the EPA published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (NESHAPS) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or "green completions" on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are required to use completion combustion device equipment (i.e., flaring) by October 15, 2012 if emissions cannot be directed to a gathering line. Further, the final rules under NESHAPS include maximum achievable control technology (MACT) standards for "small" glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. We are currently reviewing this new rule and assessing its potential impacts. Compliance with these requirements, especially the imposition of these green completion requirements, may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition to these federal legislative and regulatory proposals, some states in which we operate, such as Pennsylvania, West Virginia, Texas, Kansas, Louisiana and Montana, and certain local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, the Railroad Commission of Texas adopted rules in December 2011 requiring disclosure of certain information regarding the components used in the hydraulic fracturing process. In addition, Pennsylvania's Act 13 of 2012 became law on February 14, 2012 and amended the state's Oil and Gas Act to impose an impact fee for drilling, increase setbacks from certain water sources, require water management plans, increase civil penalties, strengthen the Pennsylvania Department of Environmental Protection's (PaDEP) authority over the issuance of drilling permits, and require the disclosure of chemical information regarding the components in hydraulic fracturing fluids.

We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our E&P operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial condition. For example, in April 2011, PaDEP called on all Marcellus Shale natural gas drilling operators to voluntarily cease by May 19, 2011 delivering wastewater to those centralized treatment facilities that were grandfathered from the application of PaDEP's Total Dissolved Solids regulations. In October 2011, the EPA announced that it plans to develop standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works (POTWs), which will be proposed in 2014. The regulations will be developed

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under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. In response to these actions, operators including us have begun to rely more on recycling of flowback and produced water from well sites as a preferred alternative to disposal.

A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing practices. The EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released of a progress report outlining work currently underway on December 21, 2012 and is expected to release a draft report of final results in 2014. This study and other studies that may be undertaken by EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources.

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

There is increasing attention in the United States and worldwide concerning the issue of climate change and the effect of greenhouse gases. In the United States, climate change action is evolving at the state, regional and federal levels. On December 17, 2010, the EPA amended the "Mandatory Reporting of Greenhouse Gases" final rule ("Reporting Rule") originally issued in September 2009. The Reporting Rule establishes a new comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent greenhouse gases to inventory and report their greenhouse gases emissions annually on a facility-by-facility basis. In addition, on December 15, 2009, the EPA published a Final Rule finding that current and projected concentrations of six key greenhouse gases in the atmosphere threaten public health and the welfare of current and future generations. The EPA also found that the combined emissions of these greenhouse gases from new motor vehicles and new motor vehicle engines contribute to pollution that threatens public health and welfare. This Final Rule, also known as the EPA's Endangerment Finding, does not impose any requirements on industry or other entities directly. However, following issuance of the Endangerment Finding, EPA promulgated final motor vehicle GHG emission standards on April 1, 2010, the effect of which could reduce demand for motor fuels refined from crude oil. Also, according to the EPA, the final motor vehicle GHG standards will trigger construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, EPA issued a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act's Prevention of Significant Deterioration ("PSD") and Title V programs. This final rule "tailors" the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi step process, with the largest sources first subject to permitting. In addition, on November 8, 2010, EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA's GHG Reporting Rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year were required to report annual GHG emissions to EPA, for the first time by September 28, 2012. We submitted our report in compliance with the deadline.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases. While it is not possible at this time to predict how regulation or legislation that may be enacted to address greenhouse gases emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States in which we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new

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regulatory or reporting requirements. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy sources) could have a negative impact on our business if such incentives reduce demand for oil and gas.

Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for greenhouse gases, became binding on all those countries that had ratified it. Ongoing international discussions following the United Nations Climate Change Conference in Doha, Qatar in December 2012 are exploring options to replace the Kyoto Protocol.

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

Certain federal income tax law changes have been proposed that, if passed, would have an adverse effect on our financial position, results of operations, and cash flows.

Substantive changes to existing federal income tax laws have been proposed that, if adopted, would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and would impose new taxes. The proposals include: repeal of the percentage depletion allowance for oil and natural gas properties; elimination of the ability to fully deduct intangible drilling costs in the year incurred; repeal of the manufacturing tax deduction for oil and gas companies; and increase in the geological and geophysical amortization period for independent producers. Should some or all of these proposals become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities in the U.S. Since none of these proposals have yet to become law, we do not know the ultimate impact these proposed changes may have on our business.

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

Our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit stockholder action by written consent and place procedural requirements and limitations on stockholder proposals at meetings of stockholders. Because of these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.

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

The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors' duty of care to equitable remedies such as injunction or rescission. Our charter limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will

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not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:

•
  for any breach of their duty of loyalty to the company or our stockholders;
•
  for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;
•
  under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and
•
  for any transaction from which the director derived an improper personal benefit.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

Legal Matters

The information set forth under the heading "Legal Matters" in Note 8 of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K is incorporated by reference in response to this item.

Environmental Matters

The information set forth under the heading "Environmental Matters" in Note 8 of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K is incorporated by reference in response to this item.

We have received a number of Notices of Violation from the PaDEP relating to alleged violations, primarily with respect to the Pennsylvania Clean Streams Law, the Pennsylvania Oil and Gas Act and the Pennsylvania Solid Waste Management Act and the rules and regulations promulgated thereunder. We have responded to these Notices of Violation, have remediated the areas in question and are actively cooperating with the PaDEP. While we cannot predict with certainty whether these Notices of Violation will result in fines and/or penalties, if fines and/or penalties are imposed, the aggregate of these fines and/or penalties could result in monetary sanctions in excess of $100,000.

On June 27, 2012, we received a letter from the United States Army Corps of Engineers (USACE) regarding our construction of 60,000 linear feet of a natural gas pipeline in Susquehanna County, Pennsylvania in 2008. The USACE alleged that construction of certain sections of the pipeline was not in compliance with the Clean Water Act. This pipeline was sold to a third party in 2010. We are actively cooperating with the USACE's investigation regarding this matter.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information as of February 21, 2013 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.

Name |  | Age |  | Position |  | Officer Since |
--- | --- | --- | --- | --- | --- | --- | ---
Dan O. Dinges |  |  | 59 |  | Chairman, President and Chief Executive Officer |  |  | 2001 |
Scott C. Schroeder |  |  | 50 |  | Vice President, Chief Financial Officer and Treasurer |  |  | 1997 |
G. Kevin Cunningham |  |  | 59 |  | Vice President, General Counsel |  |  | 2010 |
Robert G. Drake |  |  | 65 |  | Vice President, Information Services and Operational Accounting |  |  | 1998 |
Jeffrey W. Hutton |  |  | 57 |  | Vice President, Marketing |  |  | 1995 |
Todd L. Liebl |  |  | 55 |  | Vice President, Land and Business Development |  |  | 2012 |
Steven W. Lindeman |  |  | 52 |  | Vice President, Engineering and Technology |  |  | 2011 |
James M. Reid |  |  | 61 |  | Vice President, Regional Manager South Region |  |  | 2009 |
Phillip L. Stalnaker |  |  | 53 |  | Vice President, Regional Manager North Region |  |  | 2009 |
Todd M. Roemer |  |  | 42 |  | Controller |  |  | 2010 |
Deidre L. Shearer |  |  | 45 |  | Corporate Secretary and Managing Counsel |  |  | 2012 |

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

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

Mr. Liebl joined the Company in September 2008 as South Region Land Manager, promoted to Director of Land in June 2010, Director of Land and Business Development in February 2011 and Vice President in February 2012. Previously, Mr. Liebl held positions with Anadarko Petroleum and most recently Chesapeake Energy from April 2007 until he joined the Company. He holds a Bachelor of Business Administration degree in Petroleum Land Management from the University of Oklahoma.

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

Ms. Shearer joined the Company in December 2011 and was appointed Managing Counsel and Corporate Secretary in February 2012. Prior to joining the Company, Ms. Shearer was Assistant General Counsel of KBR, Inc. from January 2007, where she was responsible for corporate governance and SEC and NYSE compliance matters. Ms. Shearer received her J.D. degree from The University of Texas School of Law in 1992 and was primarily in private practice until she joined KBR.

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PART II

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

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

On January 3, 2012, the Board of Directors declared a 2-for-1 split of our common stock in the form of a stock dividend. The stock dividend was distributed on January 25, 2012 to shareholders of record on January 17, 2012. All common stock accounts and per share data, including cash dividends per share, have been retroactively adjusted to give effect to the 2-for-1 split of our common stock.

|  | High |  | Low |  | Dividends |
--- | --- | --- | --- | --- | --- | --- | ---
2012 |  |  |  |  |  |  |  |  |  |
First Quarter |  | $ | 41.36 |  | $ | 30.25 |  | $ | 0.02 |
Second Quarter |  | $ | 41.24 |  | $ | 29.54 |  | $ | 0.02 |
Third Quarter |  | $ | 45.86 |  | $ | 38.97 |  | $ | 0.02 |
Fourth Quarter |  | $ | 51.07 |  | $ | 42.94 |  | $ | 0.02 |
2011 |  |  |  |  |  |  |  |  |  |
First Quarter |  | $ | 26.70 |  | $ | 18.72 |  | $ | 0.015 |
Second Quarter |  | $ | 33.16 |  | $ | 25.47 |  | $ | 0.015 |
Third Quarter |  | $ | 38.56 |  | $ | 29.65 |  | $ | 0.015 |
Fourth Quarter |  | $ | 44.30 |  | $ | 29.29 |  | $ | 0.015 |

As of February 1, 2013, there were 445 registered holders of our common stock.

ISSUER PURCHASES OF EQUITY SECURITIES

On October 26, 2006, our Board of Directors authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During 2012, we did not repurchase any shares of common stock. All purchases executed to date have been through open market transactions. The maximum number of remaining shares that may be purchased under the plan as of December 31, 2012 was 9,590,600.

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PERFORMANCE GRAPH

The following graph compares our common stock performance ("COG") with the performance of the Standard & Poors' 500 Stock Index and the Dow Jones U.S. Exploration & Production Index for the period December 2007 through December 2012. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2007 and that all dividends were reinvested.

Calculated Values* |  | 2007 |  | 2008 |  | 2009 |  | 2010 |  | 2011 |  | 2012 |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
COG |  | $ | 100.00 |  | $ | 64.60 |  | $ | 108.69 |  | $ | 94.71 |  | $ | 190.32 |  | $ | 249.96 |
S&P 500 |  | $ | 100.00 |  | $ | 63.00 |  | $ | 79.67 |  | $ | 91.67 |  | $ | 93.61 |  | $ | 108.59 |
Dow Jones U.S. Exploration & Production |  | $ | 100.00 |  | $ | 59.88 |  | $ | 84.17 |  | $ | 98.26 |  | $ | 94.14 |  | $ | 99.62 |

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

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ITEM 6. SELECTED FINANCIAL DATA

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

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands, except per share amounts) |  | 2012 |  | 2011 |  | 2010 |  | 2009 |  | 2008 |
Statement of Operations Data |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $ | 1,204,546 |  | $ | 979,864 |  | $ | 863,104 |  | $ | 893,085 |  | $ | 956,746 |
Impairment of oil and gas properties and other assets |  |  | — |  |  | — |  |  | 40,903 |  |  | 17,622 |  |  | 35,700 |
Gain / (loss) on sale of assets(1) |  |  | 50,635 |  |  | 63,382 |  |  | 106,294 |  |  | (3,303 | ) |  | 1,143 |
Gain on settlement of dispute(2) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 51,906 |
Income from operations |  |  | 306,133 |  |  | 306,850 |  |  | 266,439 |  |  | 282,269 |  |  | 372,012 |
Net income |  |  | 131,730 |  |  | 122,408 |  |  | 103,386 |  |  | 148,343 |  |  | 211,290 |
Basic earnings per share(3) |  | $ | 0.63 |  | $ | 0.59 |  | $ | 0.50 |  | $ | 0.72 |  | $ | 1.05 |
Diluted earnings per share(3) |  | $ | 0.62 |  | $ | 0.58 |  | $ | 0.49 |  | $ | 0.71 |  | $ | 1.04 |
Dividends per common share(3) |  | $ | 0.08 |  | $ | 0.06 |  | $ | 0.06 |  | $ | 0.06 |  | $ | 0.06 |

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |  | 2009 |  | 2008 |
Balance Sheet Data |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Properties and equipment, net |  | $ | 4,310,977 |  | $ | 3,934,584 |  | $ | 3,762,760 |  | $ | 3,358,199 |  | $ | 3,135,828 |
Total assets |  |  | 4,616,313 |  |  | 4,331,493 |  |  | 4,005,031 |  |  | 3,683,401 |  |  | 3,701,664 |
Current portion of long-term debt |  |  | 75,000 |  |  | — |  |  | — |  |  | — |  |  | 35,857 |
Long-term debt |  |  | 1,012,000 |  |  | 950,000 |  |  | 975,000 |  |  | 805,000 |  |  | 831,143 |
Stockholders' equity |  |  | 2,131,447 |  |  | 2,104,768 |  |  | 1,872,700 |  |  | 1,812,514 |  |  | 1,790,562 |

(1)
  Gain on sale of assets in 2012 includes a $67.0 million gain from the sale of certain Pearsall Shale undeveloped leaseholds in south Texas and an $18.2 million loss from the sale of certain proved oil and gas properties located in south Texas. Gain on sale of assets in 2011 includes a $34.2 million gain from the sale of certain Haynesville and Bossier Shale oil and gas properties and an aggregate gain of $29.2 million from the sale of various other properties during the year. Gain on sale of assets in 2010 includes a $40.7 million from the sale of our investment in Tourmaline, a $49.3 million gain from the sale of our Pennsylvania gathering infrastructure and an aggregate gain of $16.3 million from the sale of various other properties during the year.
(2)
  Gain on settlement of dispute is associated with the Company's settlement of a dispute in the fourth quarter of 2008. The settlement include the value of cash and properties received.
(3)
  All Earnings per share and Dividends per common share figures have been retroactively adjusted for the 2-for-1 split of our common stock effective January 25, 2012.

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

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

OVERVIEW

On an equivalent basis, our production in 2012 increased by 43% from 2011. We produced 267.7 Bcfe, or 731.4 Mmcfe per day, in 2012, compared to 187.5 Bcfe, or 513.7 Mmcfe per day, in 2011. Natural gas production increased by 74.4 Bcf, or 42%, to 253.2 Bcf in 2012 compared to 178.8 Bcf in 2011. This increase was primarily the result of increased production in the Marcellus Shale associated with our drilling program and continued expansion of infrastructure in the area. Partially offsetting the production increase in the Marcellus Shale was the sale of certain oil and gas properties in the Rockies in the fourth quarter of 2011 along with decreases in production primarily in Texas, Oklahoma and West Virginia due to a shift from natural gas to liquids drilling and normal production declines. Crude oil/condensate/NGL production increased by 964 Mbbls, or 67%, from 1,443 Mbbls in 2011 to 2,407 Mbbls in 2012. This increase was primarily the result of increased production resulting from our Eagle Ford Shale drilling program in south Texas and the Marmaton oil play in Oklahoma.

Our financial results depend on many factors, particularly the price of natural gas and crude oil, and our ability to market our production on economically attractive terms. Our average realized natural gas price for 2012 was $3.67 per Mcf, 18% lower than the $4.46 per Mcf price realized in 2011. Our average realized crude oil price for 2012 was $101.65 per Bbl, 12% higher than the $90.49 per Bbl price realized in 2011. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to "Results of Operations" in Item 7. Commodity prices are determined by many factors that are outside of our control. Historically, commodity prices have been volatile, and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes or future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. See "Risk Factors—Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business" and "Risk Factors—Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable" in Item 1A.

We drilled 170 gross wells with a success rate of 98% in 2012 compared to 161 gross wells with a success rate of 99% in 2011. Our 2012 total capital and exploration spending was $978.5 million compared to $905.5 million in 2011. This increase in spending was substantially driven by an expanded Marcellus Shale horizontal drilling program in northeast Pennsylvania, the Eagle Ford Shale in south Texas, including a portion towards the Pearsall Shale, and the Marmaton oil play in Oklahoma. In both 2012 and 2011, we allocated our planned program for capital and exploration expenditures among our various operating areas based on return expectations, availability of services and human resources. We plan to continue such method of allocation in 2013. Our 2013 drilling program includes between $950.0 million and $1.0 billion in capital and exploration expenditures. Funding of the program is expected to be provided by operating cash flow, existing cash and, if required, borrowings under our credit facility.

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FINANCIAL CONDITION

Capital Resources and Liquidity

Our primary sources of cash in 2012 were from funds generated from the sale of natural gas and crude oil production (including hedge realizations), proceeds from the sales of certain oil and gas properties and other assets during the year and borrowings under our credit facility. These cash flows were primarily used to fund our capital and exploration expenditures, in addition to repayments of debt and related interest, final contributions to fund the liquidation of our pension plan and dividends. See below for additional discussion and analysis of cash flow.

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

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

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Cash flows provided by operating activities |  | $ | 652,093 |  | $ | 501,839 |  | $ | 484,911 |
Cash flows used in investing activities |  |  | (765,514 | ) |  | (487,620 | ) |  | (613,741 | )
Cash flows provided by / (used in) financing activities |  |  | 114,246 |  |  | (40,257 | ) |  | 144,621 |
Net increase / (decrease) in cash and cash equivalents |  | $ | 825 |  | $ | (26,038 | ) | $ | 15,791 |

Operating Activities

Net cash provided by operating activities in 2012 increased by $150.3 million over 2011. This increase was primarily due to higher operating revenues that outpaced the increase in operating expenses (excluding non-cash expenses). This increase was partially offset by changes in working capital and long-term assets and liabilities. The increase in operating revenues was primarily due to an increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas prices. Equivalent production volumes increased by 43% for 2012 compared to 2011 as a result of higher natural gas and crude oil production. Average realized natural gas prices decreased by 18% for 2012 compared to 2011, while average realized crude oil prices increased by 12% compared to the same period.

Net cash provided by operating activities in 2011 increased by $16.9 million over 2010. This increase was primarily due to increased operating income in 2011 as a result of higher operating revenues that outpaced the increase in operating expenses (excluding non-cash expenses). This increase was offset by changes in working capital which decreased operating cash flows. The increase in operating revenues was primarily due to an increase in equivalent production partially offset by lower realized natural gas and crude oil prices. Equivalent production volumes increased by 44% in 2011 compared to 2010 primarily due to higher natural gas and crude oil production. Average realized natural gas prices decreased by 22% in 2011 compared to 2010 and average realized crude oil prices decreased by 8% over the same period.

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See "Results of Operations" for additional information relative to commodity price, production and operating expense movements. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities. Realized prices may decline in future periods.

Investing Activities

The primary use of cash in investing activities was capital and exploration expenditures. We established our budget for these amounts based on our current estimate of future commodity prices and cash flows. Due to the volatility of commodity prices and new opportunities which may arise, our capital expenditures may be periodically adjusted during any given year.

Cash flows used in investing activities increased by $277.9 million from 2011 to 2012 and decreased by $126.1 million from 2010 to 2011. The increase from 2011 to 2012 was due to a decrease of $234.3 million of proceeds from the sale of assets, an increase of $36.7 million in capital and exploration expenditures and an increase of $6.9 million associated with our equity investment in Constitution. The decrease from 2010 to 2011 was due to an increase of $160.1 million of proceeds from the sale of assets partially offset by an increase of $34.0 million in capital and exploration expenditures.

Financing Activities

Cash flows provided by financing activities increased by $154.5 million from 2011 to 2012. This was primarily due to $162.0 million of higher net borrowings ($70.0 million increase in borrowings and $92.0 million decrease in repayment of debt), partially offset by an increase in dividends paid of $4.2 million and cash paid for capitalized debt issuance costs of $4.0 million. Cash flows used in financing activities increased by $184.9 million from 2010 to 2011. This was primarily due to a decrease in net borrowings of $195.0 million, partially offset by a decrease in cash paid for capitalized debt issuance costs of $12.8 million.

At December 31, 2012, we had $325.0 million of borrowings outstanding under our credit facility at a weighted-average interest rate of 2.2% compared to $188.0 million of borrowings outstanding at a weighted-average interest rate of 4.9% at December 31, 2011. As of December 31, 2012, we had $574.0 million available for future borrowings under our credit facility.

In May 2012, we amended our credit facility to adjust the margins associated with borrowings under the facility and extended the maturity date from September 2015 to May 2017. The credit facility, as amended, provides for an available credit line of $900 million and contains a $500 million accordion feature whereby we may increase the available credit line to $1.4 billion, if one or more of the existing banks or new banks agree to provide such increased commitment amount. As of December 31, 2012, the borrowing base under our amended credit facility was $1.7 billion. See Note 4 of the Notes to the Consolidated Financial Statements for further details.

We strive to manage our debt at a level below the available credit line in order to maintain borrowing capacity. Our credit facility includes a covenant limiting our total debt. Management believes that, with internally generated cash flow, existing cash on hand and availability under our credit facility, we have the capacity to finance our spending plans and maintain our strong financial position.

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Capitalization

Information about our capitalization is as follows:

|  | December 31, |
--- | --- | --- | ---
(Dollars in thousands) |  | 2012 |  | 2011 |
Debt(1) |  | $ | 1,087,000 |  | $ | 950,000 |
Stockholders' equity |  |  | 2,131,447 |  |  | 2,104,768 |
Total capitalization |  | $ | 3,218,447 |  | $ | 3,054,768 |
Debt to capitalization |  |  | 34% |  |  | 31% |
Cash and cash equivalents |  | $ | 30,736 |  | $ | 29,911 |

(1)
  Includes $75.0 million of current portion of long-term debt at December 31, 2012 and $325.0 million and $188.0 million of borrowings outstanding under our revolving credit facility at December 31, 2012 and 2011, respectively.

For the year ended December 31, 2012, we paid dividends of $16.8 million ($0.08 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

Capital and Exploration Expenditures

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

The following table presents major components of our capital and exploration expenditures:

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Capital Expenditures |  |  |  |  |  |  |  |  |  |
Drilling and facilities |  | $ | 843,528 |  | $ | 780,673 |  | $ | 654,153 |
Leasehold acquisitions |  |  | 88,880 |  |  | 71,134 |  |  | 130,675 |
Acquisitions |  |  | — |  |  | — |  |  | 801 |
Pipeline and gathering |  |  | 94 |  |  | 7,378 |  |  | 54,811 |
Other |  |  | 8,547 |  |  | 9,840 |  |  | 8,368 |
|  |  | 941,049 |  |  | 869,025 |  |  | 848,808 |
Exploration expense |  |  | 37,476 |  |  | 36,447 |  |  | 42,725 |
Total |  | $ | 978,525 |  | $ | 905,472 |  | $ | 891,533 |

We plan to drill approximately 170 to 180 gross wells (130 to 145 net) in 2013 compared to 170 gross wells (117.8 net) drilled in 2012. This 2013 drilling program includes between approximately $950.0 million and $1.0 billion in total capital and exploration expenditures (excluding expected contributions of approximately $12.0 million to Constitution), compared to $978.5 million in 2012. We expect our capital spending in 2013 to be consistent with that of 2012 based on our estimate of natural gas and crude oil prices over the next year. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease our capital and exploration expenditures accordingly.

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Contractual Obligations

A summary of our contractual obligations as of December 31, 2012 are set forth in the following table:

|  |  |  | Payments Due by Year |
--- | --- | --- | --- | --- | ---
(In thousands) |  | Total |  | 2013 |  | 2014 to 2015 |  | 2016 to 2017 |  | 2018 & Beyond |
Long-term debt |  | $ | 1,087,000 |  | $ | 75,000 |  | $ | — |  | $ | 345,000 |  | $ | 667,000 |
Interest on long-term debt(1) |  |  | 391,617 |  |  | 58,185 |  |  | 105,330 |  |  | 99,093 |  |  | 129,009 |
Transportation agreements(2) |  |  | 1,713,252 |  |  | 94,714 |  |  | 213,348 |  |  | 248,896 |  |  | 1,156,294 |
Drilling rig commitments(2) |  |  | 27,063 |  |  | 17,893 |  |  | 9,170 |  |  | — |  |  | — |
Operating leases(2) |  |  | 14,304 |  |  | 5,106 |  |  | 8,276 |  |  | 922 |  |  | — |
Equity investment contribution commitments(3) |  |  | 164,405 |  |  | 10,707 |  |  | 149,906 |  |  | 3,792 |  |  | — |
Total contractual obligations |  | $ | 3,397,641 |  | $ | 261,605 |  | $ | 486,030 |  | $ | 697,703 |  | $ | 1,952,303 |

(1)
  Interest payments have been calculated utilizing the fixed rates of our $1.1 billion long-term debt outstanding, including current maturities, at December 31, 2012. Interest payments on our revolving credit facility were calculated by assuming that the December 31, 2012 outstanding balance of $325.0 million will be outstanding through the May 2017 maturity date. A constant interest rate of 2.2% was assumed, which was the December 31, 2012 weighted-average interest rate. Actual results will differ from these estimates and assumptions.
(2)
  For further information on our obligations under transportation agreements, drilling rig commitments and operating leases, see Note 8 of the Notes to the Consolidated Financial Statements.
(3)
  For further information on our equity investment contribution commitment, see Note 5 of the Notes to the Consolidated Financial Statements.

Amounts related to our asset retirement obligation are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of our asset retirement obligation at December 31, 2012 was $67.0 million. See Note 9 of the Notes to the Consolidated Financial Statements for further details.

We have no off-balance sheet debt or other similar unrecorded obligations.

Potential Impact of Our Critical Accounting Policies

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

Successful Efforts Method of Accounting

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

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Oil and Gas Reserves

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

Our reserves have been prepared by our petroleum engineering staff and audited by Miller & Lents, independent petroleum engineers, who in their opinion determined the estimates presented to be reasonable in the aggregate. For more information regarding reserve estimation, including historical reserve revisions, refer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8.

Our rate of recording DD&A expense is dependent upon our estimate of proved and proved developed reserves, which are utilized in our unit-of-production calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it uneconomic to drill and produce higher cost fields. A 5% positive or negative revision to proved reserves would result in a decrease of $0.05 per Mcfe and an increase of $0.05 per Mcfe, respectively, on our DD&A rate. Revisions in significant fields may individually affect our DD&A rate. It is estimated that a positive or negative reserve revision of 10% in one of our most productive fields would result in a decrease of $0.05 per Mcfe and an increase of $0.06 per Mcfe, respectively, on our total DD&A rate. These estimated impacts are based on current data, and actual events could require different adjustments to our DD&A rate.

In addition, a decline in proved reserve estimates may impact the outcome of our impairment test under applicable accounting standards. Due to the inherent imprecision of the reserve estimation process, risks associated with the operations of proved producing properties and market sensitive commodity prices utilized in our impairment analysis, management cannot determine if an impairment is reasonably likely to occur in the future.

Carrying Value of Oil and Gas Properties

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

Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to our undeveloped acreage amortization based on past drilling and exploration experience, our expectation of converting leases to held by production and average property

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lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. Historically, the average property life in each of the geographical areas has not significantly changed and generally range from three to five years. The commodity price environment may impact the capital available for exploration projects as well as development drilling. We have considered these impacts when determining the amortization rate of our undeveloped acreage, especially in exploratory areas. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $2.3 million or decrease by approximately $1.8 million, respectively, per year.

As these properties are developed and reserves are proven, the remaining capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved properties are written off depends on the timing and success of our future exploration and development program.

Asset Retirement Obligation

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

Accounting for Derivative Instruments and Hedging Activities

Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the balance sheet. At the end of each quarterly period, these instruments are marked-to-market. The gain or loss on the change in fair value is recorded as Accumulated other comprehensive income, a component of equity, to the extent that the derivative instrument is designated as a hedge and is effective. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges and the change in fair value of derivatives not qualifying as hedges are recorded currently in earnings as a component of Natural gas and Crude oil and condensate revenue in the Consolidated Statement of Operations.

Our derivative contracts are measured based on quotes from our counterparties. Such quotes have been derived using an income approach that considers various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, basis differentials, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term, as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of fair value also incorporates a credit adjustment for non-performance risk. We measure the non-performance risk of our counterparties by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.

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Employee Benefit Plans

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

Stock-Based Compensation

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

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-11, "Disclosures about Offsetting Assets and Liabilities." The amendments in this update require enhanced disclosures around financial instruments and derivative instruments that are either (1) offset in accordance with either ASC 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. This guidance will primarily impact our disclosures associated with our commodity derivatives. We do not expect this guidance to have any impact on our consolidated financial position, results of operations or cash flows.

In January 2013, the FASB issued ASU No. 2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities." The amendments in this update clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with ASC 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. This guidance will primarily impact our disclosures associated with our commodity derivatives. We do not expect this guidance to have any impact on our consolidated financial position, results of operations or cash flows.

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OTHER ISSUES AND CONTINGENCIES

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

Restrictive Covenants. Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in our various debt instruments. Among other requirements, our revolving credit agreement and our senior notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0 and an asset coverage ratio of the present value of proved reserves plus adjusted cash to indebtedness and other liabilities of 1.75 to 1.0. Our revolving credit agreement also requires us to maintain a current ratio of 1.0 to 1.0. At December 31, 2012, we were in compliance with all restrictive financial covenants in both the revolving credit agreement and senior notes. In the unforeseen event that we fail to comply with these covenants, we may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation.

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

Commodity Pricing and Risk Management Activities. Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and crude oil. Declines in natural gas and crude oil prices may have a material adverse effect on our financial condition, liquidity, ability to obtain financing and operating results. Lower natural gas and crude oil prices also may reduce the amount of natural gas and crude oil that we can produce economically. Historically, natural gas and crude oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results. In particular, substantially lower prices would significantly reduce revenue and could potentially trigger an impairment of our long-lived assets. Because our reserves are predominantly natural gas, changes in natural gas prices may have a more significant impact on our financial results.

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

RESULTS OF OPERATIONS

2012 and 2011 Compared

We reported net income for 2012 of $131.7 million, or $0.63 per share, compared to net income for 2011 of $122.4 million, or $0.59 per share. The increase in net income was primarily due to an

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increase in equivalent production and higher realized crude oil prices partially offset by lower realized natural gas prices and higher operating costs.

Revenue, Price and Volume Variances

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

|  | Year Ended December 31, |  | Variance
--- | --- | --- | --- | ---
Revenue Variances (In thousands) |  | 2012 |  | 2011 |  | Amount |  | Percent
Natural gas(1) |  | $ | 934,134 |  | $ | 797,482 |  | $ | 136,652 |  |  | 17%
Crude oil and condensate |  |  | 227,933 |  |  | 125,972 |  |  | 101,961 |  |  | 81%
Brokered natural gas |  |  | 34,005 |  |  | 51,190 |  |  | (17,185 | ) |  | (34)%
Other |  |  | 8,968 |  |  | 6,185 |  |  | 2,783 |  |  | 45%

(1)
  Natural gas revenues exclude the unrealized loss of $0.5 million and $1.0 million from the change in fair value of our derivatives not designated as hedges in 2012 and 2011, respectively.

|  | Year Ended December 31, |  |  |  |  |  |  |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
|  | Variance |  |  |
|  | Increase (Decrease) (In thousands) |
|  | 2012 |  | 2011 |  | Amount |  | Percent |
Price Variances |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas(1) |  | $ | 3.67 |  | $ | 4.46 |  | $ | (0.79 | ) |  | (18)% |  | $ | (195,172 | )
Crude oil and condensate(2) |  | $ | 101.65 |  | $ | 90.49 |  | $ | 11.16 |  |  | 12% |  |  | 25,034 |
Total |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (170,138 | )
Volume Variances |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (Bcf) |  |  | 253.2 |  |  | 178.8 |  |  | 74.4 |  |  | 42% |  | $ | 331,824 |
Crude oil and condensate (Mbbl) |  |  | 2,242 |  |  | 1,392 |  |  | 850 |  |  | 61% |  |  | 76,927 |
Total |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 408,751 |

(1)
  These prices include the realized impact of derivative instrument settlements, which increased the price by $0.89 per Mcf in 2012 and by $0.47 per Mcf in 2011.
(2)
  These prices include the realized impact of derivative instrument settlements, which increased the price by $5.00 per Bbl in 2012 and by $1.01 per Bbl in 2011.

Natural Gas Revenues

The increase in Natural gas revenues of $136.7 million, excluding the impact of the unrealized losses discussed above, is primarily due to increased production, partially offset by lower realized natural gas prices. The increased production was primarily a result of higher production in the Marcellus Shale associated with our drilling program and expanded infrastructure, partially offset by the sale of certain oil and gas properties in the Rockies in the fourth quarter of 2011 and decreases in production primarily in Texas, Oklahoma and West Virginia due to a shift from natural gas to liquids drilling and normal production declines.

Crude Oil and Condensate Revenues

The increase in Crude oil and condensate revenues of $102.0 million is primarily due to increased production associated with our Eagle Ford Shale drilling program in south Texas and the Marmaton oil play in Oklahoma, coupled with higher realized oil prices.

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Brokered Natural Gas

|  | Year Ended December 31, |  |  |  |  |  |  |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
|  | Variance |  | Price and Volume Variances (In thousands) |
|  | 2012 |  | 2011 |  | Amount |  | Percent |
Brokered Natural Gas Sales |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sales price ($/Mcf) |  | $ | 3.57 |  | $ | 4.97 |  | $ | (1.40 | ) |  | (28)% |  | $ | (13,328 | )
Volume brokered (Mmcf) |  | x | 9,527 |  | x | 10,303 |  |  | (776 | ) |  | (8)% |  |  | (3,857 | )
Brokered natural gas (In thousands) |  | $ | 34,005 |  | $ | 51,190 |  |  |  |  |  |  |  | $ | (17,185 | )
Brokered Natural Gas Purchases |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchase price ($/Mcf) |  | $ | 2.99 |  | $ | 4.25 |  | $ | (1.26 | ) |  | (30)% |  | $ | 12,034 |
Volume brokered (Mmcf) |  | x | 9,527 |  | x | 10,303 |  |  | (776 | ) |  | (8)% |  |  | 3,298 |
Brokered natural gas (In thousands) |  | $ | 28,502 |  | $ | 43,834 |  |  |  |  |  |  |  | $ | 15,332 |
Brokered natural gas margin (In thousands) |  | $ | 5,503 |  | $ | 7,356 |  |  |  |  |  |  |  | $ | (1,853 | )

The decreased brokered natural gas margin of $1.9 million is primarily a result of a decrease in brokered volumes coupled with a decrease in sales price that outpaced the decrease in purchase price.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the increase / (decrease) to operating revenues from the realized impact of cash settlements for derivative instruments designated as cash flow hedges and the net unrealized change in fair value of other financial derivative instruments:

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |
Cash Flow Hedges |  |  |  |  |  |  |
Natural gas |  | $ | 225,108 |  | $ | 84,937 |
Crude oil |  |  | 11,218 |  |  | 1,403 |
Other Derivative Financial Instruments |  |  |  |  |  |  |
Natural gas basis swaps |  |  | (494 | ) |  | (965 | )
|  | $ | 235,832 |  | $ | 85,375 |

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Operating and Other Expenses

|  | Year Ended December 31, |  | Variance
--- | --- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | Amount |  | Percent
Operating and Other Expenses |  |  |  |  |  |  |  |  |  |  |  |
Direct operations |  | $ | 118,243 |  | $ | 107,409 |  | $ | 10,834 |  |  | 10%
Transportation and gathering |  |  | 143,309 |  |  | 73,322 |  |  | 69,987 |  |  | 95%
Brokered natural gas |  |  | 28,502 |  |  | 43,834 |  |  | (15,332 | ) |  | (35)%
Taxes other than income |  |  | 48,874 |  |  | 27,576 |  |  | 21,298 |  |  | 77%
Exploration |  |  | 37,476 |  |  | 36,447 |  |  | 1,029 |  |  | 3%
Depreciation, depletion and amortization |  |  | 451,405 |  |  | 343,141 |  |  | 108,264 |  |  | 32%
General and administrative |  |  | 121,239 |  |  | 104,667 |  |  | 16,572 |  |  | 16%
Total operating expense |  | $ | 949,048 |  | $ | 736,396 |  | $ | 212,652 |  |  | 29%
(Gain) / loss on sale of assets |  | $ | (50,635 | ) | $ | (63,382 | ) | $ | (12,747 | ) |  | (20)%
Interest expense and other |  |  | 68,293 |  |  | 71,663 |  |  | (3,370 | ) |  | (5)%
Income tax expense |  |  | 106,110 |  |  | 112,779 |  |  | (6,669 | ) |  | (6)%

Total costs and expenses from operations increased by $212.7 million from 2011 to 2012. The primary reasons for this fluctuation are as follows:

•
  Direct operations increased $10.8 million largely due to increased operating costs primarily driven by increased production. Contributing to the increase are higher employee related and lease maintenance costs, partially offset by lower workover costs.
•
  Transportation and gathering increased by $70.0 million primarily due higher throughput due to an increase in production and higher transportation rates, coupled with the commencement of various transportation and gathering arrangements in late 2011 and throughout 2012, primarily in northeast Pennsylvania and south Texas.
•
  Brokered natural gas decreased by $15.3 million from 2011 to 2012. See the preceding table titled "Brokered Natural Gas Revenue and Cost" for further analysis.
•
  Taxes other than income increased $21.3 million primarily due to additional costs associated with the passage of an "impact fee" in Pennsylvania on Marcellus Shale production that was imposed by state legislature in February 2012 and higher production tax expense due to fewer production tax refunds and credits received in 2012 compared to 2011.
•
  Exploration increased $1.0 million primarily due to an increase in exploration expense as the result of increased activity, partially offset by lower geophysical and geological costs due to fewer acquisitions and purchases of seismic data.
•
  Depreciation, depletion and amortization increased $108.3 million, with a $131.4 million increase due to higher equivalent production volumes partially offset by an $8.5 million decrease due to a lower DD&A rate. This increase was offset by a decrease in amortization of unproved properties of $14.4 million as a result of a decrease in amortization rates due to the success of our drilling programs in Pennsylvania and south Texas and the sale of certain Pearsall Shale undeveloped leaseholds in south Texas in the second quarter of 2012.

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•
  General and administrative increased by $16.6 million primarily due to $14.0 million higher pension expense associated with the termination of our qualified pension plan and the related settlement that occurred in the second quarter 2012, and higher legal costs and professional fees of $6.0 million. Also contributing to the increase was the accrual of $1.9 million associated with fines and penalties assessed by the Office of Natural Resources Revenue for certain alleged volume reporting matters (which we are currently disputing) related to properties we no longer own and a $2.2 million charitable contribution to fund the construction of a hospital in northeast Pennsylvania. These increases were partially offset by $6.3 million of lower stock-based compensation expense primarily associated with the mark-to-market of our liability-based performance awards due to changes in our stock price in 2012 compared to 2011.

Gain / (Loss) on Sale of Assets

During 2012, we recognized an aggregate gain of $50.6 million which includes a $67.0 million gain associated with the sale of certain of our Pearsall Shale undeveloped leaseholds in south Texas, partially offset by an $18.2 million loss on the sale of certain proved oil and gas properties located in south Texas. During the 2011, an aggregate gain of $63.4 million was recognized primarily due to the sale of certain undeveloped leaseholds in east Texas and the sale of other non-core assets.

Interest Expense, Net

Interest expense and other decreased by $3.4 million in 2012 compared to 2011 primarily due to a decrease in the weighted-average effective interest rate on the credit facility, which decreased to approximately 3.0% during 2012 compared to approximately 4.1% during 2011, partially offset by a decrease in weighted-average borrowings under our credit facility based on weighted-average debt of $283.8 million in 2012 compared to weighted-average debt of $317.7 million in 2011.

Income Tax Expense

Income tax expense decreased by $6.7 million in 2012 compared to 2011 primarily due a lower effective tax rate partially offset by increased pretax income. The effective tax rates for 2012 and 2011 were 44.6% and 48.0%, respectively. The effective tax rate was lower due to a decrease in the impact of our state rates used in establishing deferred income taxes.

2011 and 2010 Compared

We reported net income for 2011 of $122.4 million, or $0.59 per share, compared to net income of $103.4 million, or $0.50 per share, for 2010. The increase in net income was primarily due to an increase in equivalent production partially offset by lower realized natural gas and crude oil prices and higher operating costs.

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Revenue, Price and Volume Variances

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

|  | Year Ended December 31, |  | Variance
--- | --- | --- | --- | ---
Revenue Variances (In thousands) |  | 2011 |  | 2010 |  | Amount |  | Percent
Natural gas(1) |  | $ | 797,482 |  | $ | 713,872 |  | $ | 83,610 |  |  | 12%
Crude oil and condensate |  |  | 125,972 |  |  | 79,091 |  |  | 46,881 |  |  | 59%
Brokered natural gas |  |  | 51,190 |  |  | 65,281 |  |  | (14,091 | ) |  | (22)%
Other |  |  | 6,185 |  |  | 5,086 |  |  | 1,099 |  |  | 22%

(1)
  Natural Gas Revenues exclude the unrealized loss of $1.0 million and $0.2 million from the change in fair value of our derivatives not designated as hedges in 2011 and 2010, respectively.

|  | Year Ended December 31, |  |  |  |  |  |  |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
|  | Variance |  |  |
|  | Increase (Decrease) (In thousands) |
|  | 2011 |  | 2010 |  | Amount |  | Percent |
Price Variances |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas(1) |  | $ | 4.46 |  | $ | 5.69 |  | $ | (1.23 | ) |  | (22)% |  | $ | (219,624 | )
Crude oil and condensate(2) |  | $ | 90.49 |  | $ | 97.91 |  | $ | (7.42 | ) |  | (8)% |  |  | (10,331 | )
Total |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | (229,955 | )
Volume Variances |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas (Bcf) |  |  | 178.8 |  |  | 125.5 |  |  | 53.3 |  |  | 43% |  | $ | 303,234 |
Crude oil and condensate (Mbbl) |  |  | 1,392 |  |  | 808 |  |  | 584 |  |  | 72% |  |  | 57,212 |
Total |  |  |  |  |  |  |  |  |  |  |  |  |  | $ | 360,446 |

(1)
  These prices include the realized impact of derivative instrument settlements, which increased the price by $0.47 per Mcf in 2011 and by $1.23 per Mcf in
(2)
  These prices include the realized impact of derivative instrument settlements, which increased the price by $1.01 per Bbl in 2011 and by $22.31 per Bbl in

Natural Gas Revenues

The increase in Natural Gas revenues of $83.6 million, excluding the impact of the unrealized losses discussed above, is primarily due to increased production, partially offset by lower realized natural gas prices. The increased production is primarily due to increased production associated with our Marcellus Shale drilling program in northeast Pennsylvania, partially offset by decreases in production primarily in east and south Texas due to normal production declines, the sale of certain oil and gas properties in the Rockies and a shift from natural gas to oil projects.

Crude Oil and Condensate Revenues

The increase in Crude Oil and Condensate revenues of $46.9 million is primarily due to increased production, partially offset by lower realized oil prices. The increase in production is primarily due to our drilling program in the Eagle Ford Shale in south Texas, partially offset by lower production in east Texas due to decreased activity.

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Brokered Natural Gas

|  | Year Ended December 31, |  |  |  |  |  |  |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
|  | Variance |  | Price and Volume Variances (In thousands) |
|  | 2011 |  | 2010 |  | Amount |  | Percent |
Brokered Natural Gas Sales |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sales price ($/Mcf) |  | $ | 4.97 |  | $ | 5.41 |  | $ | (0.44 | ) |  | (8)% |  | $ | (4,533 | )
Volume brokered (Mmcf) |  | x | 10,303 |  | x | 12,072 |  |  | (1,769 | ) |  | (15)% |  |  | (9,558 | )
Brokered natural gas (In thousands) |  | $ | 51,190 |  | $ | 65,281 |  |  |  |  |  |  |  | $ | (14,091 | )
Brokered Natural Gas Purchases |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Purchase price ($/Mcf) |  | $ | 4.25 |  | $ | 4.68 |  | $ | (0.43 | ) |  | (9)% |  | $ | 4,353 |
Volume brokered (Mmcf) |  | x | 10,303 |  | x | 12,072 |  |  | (1,769 | ) |  | (15)% |  |  | 8,279 |
Brokered natural gas (In thousands) |  | $ | 43,834 |  | $ | 56,466 |  |  |  |  |  |  |  | $ | 12,632 |
Brokered natural gas margin (In thousands) |  | $ | 7,356 |  | $ | 8,815 |  |  |  |  |  |  |  | $ | (1,459 | )

The decreased brokered natural gas margin of $1.5 million is primarily a result of a decrease in brokered volumes coupled with a decrease in the sales price that slightly outpaced the decrease in purchase price.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the increase / (decrease) to operating revenues from the realized impact of cash settlements for derivative instruments designated as cash flow hedges and the net unrealized change in fair value of other financial derivative instruments:

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2011 |  | 2010 |
Cash Flow Hedges |  |  |  |  |  |  |
Natural gas |  | $ | 84,937 |  | $ | 154,960 |
Crude oil |  |  | 1,403 |  |  | 18,030 |
Other Derivative Financial Instruments |  |  |  |  |  |  |
Natural gas basis swaps |  |  | (965 | ) |  | (226 | )
|  | $ | 85,375 |  | $ | 172,764 |

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Operating and Other Expenses

|  | Year Ended December 31, |  | Variance
--- | --- | --- | --- | ---
(In thousands) |  | 2011 |  | 2010 |  | Amount |  | Percent
Operating and Other Expenses |  |  |  |  |  |  |  |  |  |  |  |
Direct operations |  | $ | 107,409 |  | $ | 99,642 |  | $ | 7,767 |  |  | 8%
Transportation and gathering |  |  | 73,322 |  |  | 19,069 |  |  | 54,253 |  |  | 285%
Brokered natural gas |  |  | 43,834 |  |  | 56,466 |  |  | (12,632 | ) |  | (22)%
Taxes other than income |  |  | 27,576 |  |  | 37,894 |  |  | (10,318 | ) |  | (27)%
Exploration |  |  | 36,447 |  |  | 42,725 |  |  | (6,278 | ) |  | (15)%
Depreciation, depletion and amortization |  |  | 343,141 |  |  | 327,083 |  |  | 16,058 |  |  | 5%
Impairment of oil and gas properties and other assets |  |  | — |  |  | 40,903 |  |  | (40,903 | ) |  | (100)%
General and administrative |  |  | 104,667 |  |  | 79,177 |  |  | 25,490 |  |  | 32%
Total operating expense |  | $ | 736,396 |  | $ | 702,959 |  | $ | 33,437 |  |  | 5%
(Gain) / loss on sale of assets |  | $ | (63,382 | ) | $ | (106,294 | ) | $ | (42,912 | ) |  | (40)%
Interest expense and other |  |  | 71,663 |  |  | 67,941 |  |  | 3,722 |  |  | 5%
Income tax expense |  |  | 112,779 |  |  | 95,112 |  |  | 17,667 |  |  | 19%

Total costs and expenses from operations increased by $33.4 million from 2010 to 2011. The primary reasons for this fluctuation are as follows:

•
  Direct operations increased $7.8 million largely due to increased operating costs primarily driven by increased production. Contributing to the increase are higher workover and environmental and regulatory costs associated with the remediation of certain wells in northeast Pennsylvania as a result of the PaDEP consent order and settlement agreement. Offsetting these increases were lower lease maintenance, subsurface lease maintenance and plugging and abandonment costs in 2011 compared to 2010 coupled with lower compression expenses primarily due to the sale of our gathering system in northeast Pennsylvania in the fourth quarter of 2010.
•
  Transportation and gathering increased by $54.3 million primarily due to the commencement of various firm transportation and gathering arrangements in 2011, primarily in northeast Pennsylvania.
•
  Brokered natural gas decreased by $12.6 million from 2010 to 2011. See the preceding table titled "Brokered Natural Gas" for further analysis.
•
  Taxes other than income decreased $10.3 million due to decreased production taxes as a result of tax refunds and credits received in 2011 on qualifying wells, lower ad valorem tax expense due to lower natural gas prices and property values and lower franchise tax expense.
•
  Exploration decreased $6.3 million due to lower geological and geophysical costs primarily due to a reduction in the acquisition of seismic data, partially offset by higher dry hole costs in 2011 related to an exploratory dry hole in Montana.
•
  Depreciation, depletion and amortization increased by $16.1 million, of which $29.8 million was due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes offset by a lower DD&A rate and a $1.4 million increase in accretion of asset retirement obligations. The increase in depreciation and depletion was partially offset by a decrease in amortization of unproved properties of $15.1 million primarily due to a decrease in amortization rates due to a shift in our drilling and development activities.
•
  Impairment of oil and gas properties decreased by $40.9 million from 2011 to 2010 due to the impairment of two south Texas fields recognized as a result of commodity price declines and

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limited activity and the impairment of drilling and service equipment in 2010. There were no impairments in 2011.

•
  General and administrative increased by $25.5 million primarily due to an increase in stock-based compensation expense of $25.1 million primarily associated with the mark to market of the liability portion of our performance shares due to changes in our stock price in 2011 compared 2010. Higher incentive compensation and fringe benefits also contributed to the increase. These increases are partially offset by lower legal and professional costs associated with the PaDEP consent order and settlement agreement executed in 2010.

Gain / (Loss) on Sale of Assets

During 2011, we recognized a gain of $34.2 million from the sale of oil and gas properties in east Texas and an aggregate gain of $29.2 million related to the sale of various other non-core assets. During 2010, we recognized a gain of $49.3 million from the sale of our Pennsylvania gathering infrastructure, $40.7 million from the sale of our investment in Tourmaline and an aggregate gain of $16.3 million related to the sale of various other oil and gas properties and other assets during the year.

Interest Expense, Net

Interest expense and other increased by $3.7 million in 2011 compared to 2010 primarily due to an increase in the weighted-average effective interest rate on the credit facility, which increased to approximately 4.1% during the 2011 compared to approximately 3.8% during 2010, partially offset by a decrease in weighted-average borrowings under our credit facility based on average daily balances of $317.7 million during 2011 compared to average daily balances of $340.4 million during 2010. In addition, in December 2010, we issued $175 million aggregate principal amount of 5.58% weighted-average fixed rate notes, which increased interest expense recognized in 2011.

Income Tax Expense

Income tax expense increased by $17.7 million in 2011 compared to 2010 primarily due to increased pretax income and a slightly higher effective tax rate. The effective tax rates for 2011 and 2010 were 48.0% and 47.9%, respectively. The effective tax rate was slightly higher primarily due to an increase in our state rates used in establishing deferred income taxes mainly due to a continued shift in our state apportionment factors to higher rate states, primarily Pennsylvania, as a result of our continued focus on development of our Marcellus Shale properties.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

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

Derivative Instruments and Hedging Activity

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

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hedges. Please read the discussion below as well as Note 13 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.

Periodically, we enter into commodity derivative instruments, including collar and swap agreements, to hedge our exposure to price fluctuations on natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. All of our derivatives are used for risk management purposes and are not held for trading purposes. Under the collar agreements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. Under the swap agreements, we receive a fixed price on a notional quantity of natural gas or crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.

As of December 31, 2012, we had the following outstanding commodity derivatives designated as hedging instruments:

Commodity and Derivative Type |  | Weighted-Average Contract Price |  | Volume |  | Contract Period |  | Net Unrealized Gain / (Loss) (In thousands) |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Natural gas collars |  | $3.09 Floor / $4.12 Ceiling per Mcf |  |  | 35.5 Bcf |  | Jan. 2013 - Dec. 2013 |  | $ | (2,807 | )
Natural gas collars |  | $3.35 Floor / $4.01 Ceiling per Mcf |  |  | 35.5 Bcf |  | Jan. 2013 - Dec. 2013 |  |  | (1,021 | )
Natural gas collars |  | $3.40 Floor / $4.12 Ceiling per Mcf |  |  | 17.7 Bcf |  | Jan. 2013 - Dec. 2013 |  |  | 287 |
Natural gas collars |  | $3.60 Floor / $4.17 Ceiling per Mcf |  |  | 17.7 Bcf |  | Jan. 2013 - Dec. 2013 |  |  | 2,290 |
Natural gas collars |  | $3.76 Floor / $4.16 Ceiling per Mcf |  |  | 17.7 Bcf |  | Jan. 2013 - Dec. 2013 |  |  | 5,765 |
Natural gas collars |  | $3.86 Floor / $4.34 Ceiling per Mcf |  |  | 17.7 Bcf |  | Jan. 2013 - Dec. 2013 |  |  | 7,586 |
Natural gas collars |  | $5.15 Floor / $6.20 Ceiling per Mcf |  |  | 17.7 Bcf |  | Jan. 2013 - Dec. 2013 |  |  | 29,090 |
Crude oil swaps |  | $101.90 per Bbl |  |  | 1,095 Mbbl |  | Jan. 2013 - Dec. 2013 |  |  | 9,482 |
|  |  |  |  |  |  |  |  | $ | 50,672 |

The amounts set forth under the net unrealized gain / (loss) column in the table above represent our total unrealized derivative position at December 31, 2012 and exclude the impact of nonperformance risk. Nonperformance risk was primarily evaluated by reviewing credit default swap spreads for the various financial institutions in which we have derivative transactions, while our non-performance risk is evaluated using a market credit spread provided by one of our banks.

During 2012, natural gas and crude oil swaps covered 96.0 Bcf, or 38%, and 1,709 Mbbl, or 76%, of natural gas and crude oil production at an average price of $5.22 per Mcf and $100.12 per Bbl, respectively. Natural gas basis swaps covered 17 Bcf, or 7%, of our natural gas production at an average price of $(0.25) per Mcf. Natural gas collars with a floor price of $3.60 per Mcf and a ceiling price of $4.17 per Mcf covered 3.0 Bcf, or 1%, of our natural gas production at an average price of $3.70 per Mcf.

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

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Fair Market Value of Other Financial Instruments

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

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

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

|  | December 31, 2012 |  | December 31, 2011 |
--- | --- | --- | --- | --- | ---
(In thousands) |  | Carrying Amount |  | Estimated Fair Value |  | Carrying Amount |  | Estimated Fair Value |
Long-term debt |  | $ | 1,087,000 |  | $ | 1,213,474 |  | $ | 950,000 |  | $ | 1,082,531 |
Current maturities |  |  | (75,000 | ) |  | (77,175 | ) |  | — |  |  | — |
Long-term debt, excluding current maturities |  | $ | 1,012,000 |  | $ | 1,136,299 |  | $ | 950,000 |  | $ | 1,082,531 |

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

|  | Page |
--- | --- | --- | ---
Report of Independent Registered Public Accounting Firm |  |  | 58 |
Consolidated Balance Sheet at December 31, 2012 and 2011 |  |  | 59 |
Consolidated Statement of Operations for the Years Ended December 31, 2012, 2011 and 2010 |  |  | 60 |
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010 |  |  | 61 |
Consolidated Statement of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010 |  |  | 62 |
Consolidated Statement of Stockholders' Equity for the Years Ended December 31, 2012, 2011 and 2010 |  |  | 63 |
Notes to the Consolidated Financial Statements |  |  | 64 |
Supplemental Oil and Gas Information (Unaudited) |  |  | 106 |
Quarterly Financial Information (Unaudited) |  |  | 111 |

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, comprehensive income, stockholders' equity and of cash flows present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries (the "Company") at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 28, 2013

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CABOT OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEET

|  | December 31, |
--- | --- | --- | ---
(In thousands, except share amounts) |  | 2012 |  | 2011 |
ASSETS |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 30,736 |  | $ | 29,911 |
Accounts receivable, net |  |  | 172,419 |  |  | 114,381 |
Income taxes receivable |  |  | — |  |  | 1,388 |
Inventories |  |  | 14,173 |  |  | 21,278 |
Derivative instruments |  |  | 50,824 |  |  | 174,263 |
Other current assets |  |  | 2,158 |  |  | 4,579 |
Total current assets |  |  | 270,310 |  |  | 345,800 |
Properties and equipment, net (Successful efforts method) |  |  | 4,310,977 |  |  | 3,934,584 |
Derivative instruments |  |  | — |  |  | 21,249 |
Other assets |  |  | 35,026 |  |  | 29,860 |
|  | $ | 4,616,313 |  | $ | 4,331,493 |
LIABILITIES AND STOCKHOLDERS' EQUITY |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |
Accounts payable |  | $ | 312,480 |  | $ | 217,294 |
Current portion of long-term debt |  |  | 75,000 |  |  | — |
Income taxes payable |  |  | 1,667 |  |  | — |
Deferred income taxes |  |  | 5,203 |  |  | 55,132 |
Accrued liabilities |  |  | 49,789 |  |  | 70,918 |
Total current liabilities |  |  | 444,139 |  |  | 343,344 |
Postretirement benefits |  |  | 38,864 |  |  | 38,708 |
Long-term debt |  |  | 1,012,000 |  |  | 950,000 |
Deferred income taxes |  |  | 882,672 |  |  | 802,592 |
Asset retirement obligation |  |  | 67,016 |  |  | 60,142 |
Other liabilities |  |  | 40,175 |  |  | 31,939 |
Total liabilities |  |  | 2,484,866 |  |  | 2,226,725 |
Commitments and contingencies |  |  |  |  |  |  |
Stockholders' equity |  |  |  |  |  |  |
Common stock: |  |  |  |  |  |  |
Authorized—480,000,000 shares of $0.10 par value in 2012 and 240,000,000 shares of $0.10 par value in 2011 |  |  |  |  |  |  |
Issued—210,429,731 shares and 209,019,458 shares in 2012 and 2011, respectively |  |  | 21,043 |  |  | 20,902 |
Additional paid-in capital |  |  | 716,609 |  |  | 724,377 |
Retained earnings |  |  | 1,373,264 |  |  | 1,258,291 |
Accumulated other comprehensive income |  |  | 23,880 |  |  | 104,547 |
Less treasury stock, at cost: |  |  |  |  |  |  |
404,400 shares in 2012 and 2011, respectively |  |  | (3,349 | ) |  | (3,349 | )
Total stockholders' equity |  |  | 2,131,447 |  |  | 2,104,768 |
|  | $ | 4,616,313 |  | $ | 4,331,493 |

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands, except per share amounts) |  | 2012 |  | 2011 |  | 2010 |
OPERATING REVENUES |  |  |  |  |  |  |  |  |  |
Natural gas |  | $ | 933,640 |  | $ | 796,517 |  | $ | 713,646 |
Crude oil and condensate |  |  | 227,933 |  |  | 125,972 |  |  | 79,091 |
Brokered natural gas |  |  | 34,005 |  |  | 51,190 |  |  | 65,281 |
Other |  |  | 8,968 |  |  | 6,185 |  |  | 5,086 |
|  |  | 1,204,546 |  |  | 979,864 |  |  | 863,104 |
OPERATING EXPENSES |  |  |  |  |  |  |  |  |  |
Direct operations |  |  | 118,243 |  |  | 107,409 |  |  | 99,642 |
Transportation and gathering |  |  | 143,309 |  |  | 73,322 |  |  | 19,069 |
Brokered natural gas cost |  |  | 28,502 |  |  | 43,834 |  |  | 56,466 |
Taxes other than income |  |  | 48,874 |  |  | 27,576 |  |  | 37,894 |
Exploration |  |  | 37,476 |  |  | 36,447 |  |  | 42,725 |
Depreciation, depletion and amortization |  |  | 451,405 |  |  | 343,141 |  |  | 327,083 |
Impairment of oil and gas properties and other assets |  |  | — |  |  | — |  |  | 40,903 |
General and administrative |  |  | 121,239 |  |  | 104,667 |  |  | 79,177 |
|  |  | 949,048 |  |  | 736,396 |  |  | 702,959 |
Gain/(loss) on sale of assets |  |  | 50,635 |  |  | 63,382 |  |  | 106,294 |
INCOME FROM OPERATIONS |  |  | 306,133 |  |  | 306,850 |  |  | 266,439 |
Interest expense and other |  |  | 68,293 |  |  | 71,663 |  |  | 67,941 |
Income before income taxes |  |  | 237,840 |  |  | 235,187 |  |  | 198,498 |
Income tax expense |  |  | 106,110 |  |  | 112,779 |  |  | 95,112 |
NET INCOME |  | $ | 131,730 |  | $ | 122,408 |  | $ | 103,386 |
Earnings per share |  |  |  |  |  |  |  |  |  |
Basic |  | $ | 0.63 |  | $ | 0.59 |  | $ | 0.50 |
Diluted |  | $ | 0.62 |  | $ | 0.58 |  | $ | 0.49 |
Weighted-average common shares outstanding |  |  |  |  |  |  |  |  |  |
Basic |  |  | 209,538 |  |  | 208,498 |  |  | 207,823 |
Diluted |  |  | 210,993 |  |  | 210,761 |  |  | 210,390 |
Dividends per common share |  | $ | 0.08 |  | $ | 0.06 |  | $ | 0.06 |

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Net income |  | $ | 131,730 |  | $ | 122,408 |  | $ | 103,386 |
Other comprehensive income / (loss), net of taxes: |  |  |  |  |  |  |  |  |  |
Reclassification adjustment for settled hedge contracts(1) |  |  | (144,456 | ) |  | (52,840 | ) |  | (107,256 | )
Changes in fair value of hedge contracts(2) |  |  | 53,815 |  |  | 163,704 |  |  | 45,878 |
Defined benefit pension and postretirement plans: |  |  |  |  |  |  |  |  |  |
Net gain / (loss)(3) |  |  | 1,258 |  |  | (13,814 | ) |  | 5,693 |
Plan termination and amendment(4) |  |  | — |  |  | — |  |  | 506 |
Settlement(5) |  |  | — |  |  | 3,380 |  |  | 2,493 |
Amortization of net obligation at transition(6) |  |  | — |  |  | 387 |  |  | 392 |
Amortization of prior service cost(7) |  |  | 134 |  |  | 640 |  |  | 355 |
Amortization of net loss(8) |  |  | 8,582 |  |  | 6,718 |  |  | 5,788 |
Foreign currency translation adjustment(9) |  |  | — |  |  | 55 |  |  | 32 |
Total other comprehensive income / (loss) |  |  | (80,667 | ) |  | 108,230 |  |  | (46,119 | )
Comprehensive income / (loss) |  | $ | 51,063 |  | $ | 230,638 |  | $ | 57,267 |

(1)
  Net of income taxes of $91,870, $33,500 and $65,734 for the year ended December 31, 2012, 2011 and 2010, respectively.
(2)
  Net of income taxes of $(34,890), $(103,963) and $(29,777) for the year ended December 31, 2012, 2011 and 2010, respectively.
(3)
  Net of income taxes of $(815), $9,085 and $(3,245) for the year ended December 31, 2012, 2011 and 2010, respectively.
(4)
  Net of income taxes of $0, $0 and $(310) for the year ended December 31, 2012, 2011 and 2010, respectively.
(5)
  Net of income taxes of $0, $(2,143) and $(1,528) for the year ended December 31, 2012, 2011 and 2010, respectively.
(6)
  Net of income taxes of $0, $(245) and $(240) for the year ended December 31, 2012, 2011 and 2010, respectively.
(7)
  Net of income taxes of $(87), $(406) and $(217) for the year ended December 31, 2012, 2011 and 2010, respectively.
(8)
  Net of income taxes of $(5,324), $(4,257) and $(3,548) for the year ended December 31, 2012, 2011 and 2010, respectively.
(9)
  Net of income taxes of $0, $(34) and $(20) for the year ended December 31, 2012, 2011 and 2010, respectively.

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
CASH FLOWS FROM OPERATING ACTIVITIES |  |  |  |  |  |  |  |  |  |
Net income |  | $ | 131,730 |  | $ | 122,408 |  | $ | 103,386 |
Adjustments to reconcile net income to cash provided by operating activities: |  |  |  |  |  |  |  |  |  |
Depreciation, depletion and amortization |  |  | 451,405 |  |  | 343,141 |  |  | 327,083 |
Impairment of oil and gas properties and other assets |  |  | — |  |  | — |  |  | 40,903 |
Deferred income tax expense |  |  | 80,929 |  |  | 74,744 |  |  | 61,809 |
(Gain) / loss on sale of assets |  |  | (50,635 | ) |  | (63,382 | ) |  | (106,294 | )
Exploration expense |  |  | 14,000 |  |  | 13,977 |  |  | 11,657 |
Unrealized (gain) / loss on derivative instruments |  |  | 494 |  |  | 965 |  |  | 226 |
Amortization of debt issuance costs |  |  | 5,265 |  |  | 4,381 |  |  | 3,381 |
Stock-based compensation, pension and other |  |  | 46,872 |  |  | 52,940 |  |  | 29,794 |
Changes in assets and liabilities: |  |  |  |  |  |  |  |  |  |
Accounts receivable, net |  |  | (58,037 | ) |  | (19,893 | ) |  | (14,125 | )
Income taxes |  |  | 3,055 |  |  | (27,345 | ) |  | 34,866 |
Inventories |  |  | 7,104 |  |  | 7,708 |  |  | (1,677 | )
Other current assets |  |  | (1,198 | ) |  | 1,143 |  |  | 3,675 |
Accounts payable and accrued liabilities |  |  | 18,843 |  |  | 8,546 |  |  | (1,488 | )
Other assets and liabilities |  |  | 2,266 |  |  | (17,494 | ) |  | (8,285 | )
Net cash provided by operating activities |  |  | 652,093 |  |  | 501,839 |  |  | 484,911 |
CASH FLOWS FROM INVESTING ACTIVITIES |  |  |  |  |  |  |  |  |  |
Capital expenditures |  |  | (927,977 | ) |  | (891,277 | ) |  | (857,251 | )
Proceeds from sale of assets |  |  | 169,326 |  |  | 403,657 |  |  | 243,510 |
Investment in equity method investment |  |  | (6,863 | ) |  | — |  |  | — |
Net cash used in investing activities |  |  | (765,514 | ) |  | (487,620 | ) |  | (613,741 | )
CASH FLOWS FROM FINANCING ACTIVITIES |  |  |  |  |  |  |  |  |  |
Borrowings from debt |  |  | 400,000 |  |  | 330,000 |  |  | 525,000 |
Repayments of debt |  |  | (263,000 | ) |  | (355,000 | ) |  | (355,000 | )
Dividends paid |  |  | (16,757 | ) |  | (12,508 | ) |  | (12,467 | )
Capitalized debt issuance costs |  |  | (5,005 | ) |  | (1,025 | ) |  | (13,821 | )
Other |  |  | (992 | ) |  | (1,724 | ) |  | 909 |
Net cash provided by / (used in) financing activities |  |  | 114,246 |  |  | (40,257 | ) |  | 144,621 |
Net increase / (decrease) in cash and cash equivalents |  |  | 825 |  |  | (26,038 | ) |  | 15,791 |
Cash and cash equivalents, beginning of period |  |  | 29,911 |  |  | 55,949 |  |  | 40,158 |
Cash and cash equivalents, end of period |  | $ | 30,736 |  | $ | 29,911 |  | $ | 55,949 |

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(In thousands, except per share amounts) |  | Common Shares |  | Stock Par |  | Treasury Shares |  | Treasury Stock |  | Paid-In Capital |  | Accumulated Other Comprehensive Income / (Loss) |  | Retained Earnings |  | Total |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Balance at December 31, 2009 |  |  | 207,712 |  | $ | 20,772 |  |  | 404 |  | $ | (3,349 | ) | $ | 695,183 |  | $ | 42,436 |  | $ | 1,057,472 |  | $ | 1,812,514 |
Net income |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 103,386 |  |  | 103,386 |
Exercise of stock options and stock appreciation rights |  |  | 78 |  |  | 8 |  |  | — |  |  | — |  |  | 762 |  |  | — |  |  | — |  |  | 770 |
Tax benefit of stock-based compensation |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 108 |  |  | — |  |  | — |  |  | 108 |
Stock amortization and vesting |  |  | 630 |  |  | 62 |  |  | — |  |  | — |  |  | 12,868 |  |  | — |  |  | — |  |  | 12,930 |
Sale of stock held in rabbi trust |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1,578 |  |  | — |  |  | — |  |  | 1,578 |
Cash dividends at $0.06 per share |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (12,467 | ) |  | (12,467 | )
Other comprehensive income / (loss) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (46,119 | ) |  | — |  |  | (46,119 | )
Balance at December 31, 2010 |  |  | 208,420 |  | $ | 20,842 |  |  | 404 |  | $ | (3,349 | ) | $ | 710,499 |  | $ | (3,683 | ) | $ | 1,148,391 |  | $ | 1,872,700 |
Net income |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 122,408 |  |  | 122,408 |
Exercise of stock options and stock appreciation rights |  |  | 159 |  |  | 16 |  |  | — |  |  | — |  |  | (1,762 | ) |  | — |  |  | — |  |  | (1,746 | )
Stock amortization and vesting |  |  | 440 |  |  | 44 |  |  | — |  |  | — |  |  | 13,906 |  |  | — |  |  | — |  |  | 13,950 |
Sale of stock held in rabbi trust |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1,734 |  |  | — |  |  | — |  |  | 1,734 |
Cash dividends at $0.06 per share |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (12,508 | ) |  | (12,508 | )
Other comprehensive income / (loss) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 108,230 |  |  | — |  |  | 108,230 |
Balance at December 31, 2011 |  |  | 209,019 |  | $ | 20,902 |  |  | 404 |  | $ | (3,349 | ) | $ | 724,377 |  | $ | 104,547 |  | $ | 1,258,291 |  | $ | 2,104,768 |
Net income |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 131,730 |  |  | 131,730 |
Exercise of stock options and stock appreciation rights |  |  | 219 |  |  | 22 |  |  | — |  |  | — |  |  | (6,730 | ) |  | — |  |  | — |  |  | (6,708 | )
Stock amortization and vesting |  |  | 1,192 |  |  | 119 |  |  | — |  |  | — |  |  | (1,038 | ) |  | — |  |  | — |  |  | (919 | )
Cash dividends at $0.08 per share |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (16,757 | ) |  | (16,757 | )
Other comprehensive income / (loss) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (80,667 | ) |  | — |  |  | (80,667 | )
Balance at December 31, 2012 |  |  | 210,430 |  | $ | 21,043 |  |  | 404 |  | $ | (3,349 | ) | $ | 716,609 |  | $ | 23,880 |  | $ | 1,373,264 |  | $ | 2,131,447 |

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

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Nature of Operations

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

The Company operates in one segment, natural gas and crude oil development, exploitation and exploration. The Company's oil and gas properties are managed as a whole rather than through discrete operating segments or business units. Operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company's entire portfolio without regard to geographic areas.

The consolidated financial statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions. Certain reclassifications have been made to prior year statements to conform with current year presentation. These reclassifications have no impact on net income.

On January 3, 2012, the Board of Directors declared a 2-for-1 split of the Company's common stock in the form of a stock dividend. The stock dividend was distributed on January 25, 2012 to shareholders of record as of January 17, 2012. All common stock accounts and per share data have been retroactively adjusted to give effect to the 2-for-1 split of the Company's common stock.

Recent Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-11, "Disclosures about Offsetting Assets and Liabilities." The amendments in this update require enhanced disclosures around financial instruments and derivative instruments that are either (1) offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. An entity should provide the disclosures required by those amendments retrospectively for all comparative periods presented. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. This guidance will primarily impact the Company's disclosures associated with its commodity derivatives. The Company does not expect this guidance to have any impact on its consolidated financial position, results of operations or cash flows.

In January 2013, the FASB issued ASU No. 2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities." The amendments in this update clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with ASC 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. The amendments are effective during interim and annual periods beginning on or after January 1, 2013. This guidance will primarily impact the Company's disclosures

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associated with its commodity derivatives. The Company does not expect this guidance to have any impact on its consolidated financial position, results of operations or cash flows.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with a maturity of three months or less and deposits in money market funds that are readily convertible to cash to be cash equivalents. Cash and cash equivalents were primarily concentrated in one financial institution at December 31, 2012 and 2011. The Company periodically assesses the financial condition of its financial institutions and considers any possible credit risk to be minimal.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts for receivables that the Company determines to be uncollectible based on the specific identification method.

Inventories

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

Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to market prices.

Equity Method Investment

The Company accounts for its investment in entities over which the Company has significant influence, but not control, using the equity method of accounting. Under the equity method of accounting, the Company records its proportionate share of net earnings, declared dividends and partnership distributions based on the most recently available financial statements of the investee. The Company also evaluates its equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other-than-temporary decline in the value of the investment.

Properties and Equipment

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

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to exploration expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production

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can begin, the cost of drilling the exploratory well will continue to be carried as an asset pending determination of whether proved reserves have been found only as long as: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well if the required capital expenditure is made and (ii) drilling of an additional exploratory well is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired and its costs are charged to exploration expense.

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

Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.

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

Unproved oil and gas properties are assessed periodically for impairment on an aggregate basis through periodic updates to the Company's undeveloped acreage amortization based on past drilling and exploration experience, the Company's expectation of converting leases to held by production and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights. During 2012, 2011 and 2010, amortization associated with the Company's unproved properties was $18.1 million, $32.5 million and $47.6 million, respectively, and is included in Depreciation, depletion, and amortization in the Consolidated Statement of Operations.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement

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cost is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost is allocated to expense using a systematic and rational method over the asset's useful life. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities are also recorded for meter stations, pipelines, processing plants and compressors. At December 31, 2012, there were no assets legally restricted for purposes of settling asset retirement obligations.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense is included in Depreciation, depletion and amortization expense in the Consolidated Statement of Operations.

Risk Management Activities

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

When the designated item associated with a derivative instrument matures or is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge.

Revenue Recognition

Producer Gas Imbalances

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

Brokered Natural Gas Margin

Revenues and expenses related to brokering natural gas are reported gross as part of operating revenues and operating expenses in accordance with applicable accounting standards. The Company realizes brokered margin as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company and/or the counterparty

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takes title to the natural gas purchased or sold. The Company realized $5.5 million, $7.4 million and $8.8 million of brokered natural gas margin in 2012, 2011 and 2010, respectively.

Income Taxes

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

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

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

Stock-Based Compensation

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

The tax benefit for stock-based compensation is included as both a cash inflow from financing activities and a cash outflow from operating activities in the Consolidated Statement of Cash Flows. The Company recognizes a tax benefit only to the extent it reduces the Company's income taxes payable. The Company did not recognize a tax benefit for stock-based compensation for the years ended December 31, 2012, 2011 and 2010.

Environmental Matters

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

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Credit and Concentration Risk

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

In 2012, three customers accounted for approximately 18%, 12% and 10%, respectively, of the Company's total sales. In 2011, the Company did not have any one customer account for greater than 10% of the Company's total sales. In 2010, one customer accounted for approximately 11%, of the Company's total sales.

Use of Estimates

In preparing financial statements, the Company follows accounting principles generally accepted in the United States of America. These principles require management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas and crude oil revenues and expenses, current values of derivative instruments, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, asset retirement obligations, pension and postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |
Proved oil and gas properties |  | $ | 5,724,940 |  | $ | 5,006,846 |
Unproved oil and gas properties |  |  | 467,483 |  |  | 478,942 |
Gathering and pipeline systems |  |  | 239,656 |  |  | 238,660 |
Land, building and other equipment |  |  | 86,137 |  |  | 80,908 |
|  |  | 6,518,216 |  |  | 5,805,356 |
Accumulated depreciation, depletion and amortization |  |  | (2,207,239 | ) |  | (1,870,772 | )
|  | $ | 4,310,977 |  | $ | 3,934,584 |

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2. Properties and Equipment, Net (Continued)

Capitalized Exploratory Well Costs

The following table reflects the net changes in capitalized exploratory well costs:

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Beginning balance at January 1 |  | $ | 5,328 |  | $ | 4,285 |  | $ | 4,179 |
Additions to capitalized exploratory well costs pending the determination of proved reserves |  |  | 10,390 |  |  | 5,328 |  |  | 4,285 |
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves |  |  | — |  |  | (1,138 | ) |  | (4,148 | )
Capitalized exploratory well costs charged to expense |  |  | (5,328 | ) |  | (3,147 | ) |  | (31 | )
Ending balance at December 31 |  | $ | 10,390 |  | $ | 5,328 |  | $ | 4,285 |

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed:

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Capitalized exploratory well costs that have been capitalized for a period of one year or less |  | $ | 10,390 |  | $ | 5,328 |  | $ | 4,285 |
Capitalized exploratory well costs that have been capitalized for a period greater than one year |  |  | — |  |  | — |  |  | — |
|  | $ | 10,390 |  | $ | 5,328 |  | $ | 4,285 |

Impairments

During 2010, the Company recorded an impairment of $40.9 million associated with its oil and gas properties and other assets. The Company recorded a $35.8 million impairment of oil and gas properties due to price declines and limited activity in two south Texas fields. These fields were reduced to fair value of approximately $15.4 million. An impairment of $5.1 million was recorded related to drilling and service equipment that was primarily used for drilling activities in West Virginia. The impairment was a result of decreased activity in West Virginia and the decision to sell the drilling and service equipment. These assets were reduced to fair value of approximately $4.0 million.

The Company also recorded an impairment loss of approximately $5.8 million during 2010 associated with the sale of certain properties in Colorado, which was recognized in Gain / (loss) on sale of assets in the Consolidated Statement of Operations. The fair value of the impaired properties was approximately $3.0 million and was determined using a market approach which considered the execution of a purchase and sale agreement the Company entered into on June 30, 2010. Accordingly, the inputs associated with the fair value of assets held for sale were considered Level 2 in the fair value hierarchy.

Fair value of oil and gas properties was determined using the income approach utilizing discounted future cash flows. The fair value of the impaired oil and gas properties and other assets was based on significant inputs that were not observable in the market and are considered to be Level 3 inputs. Refer to Note 14 for more information and a description of fair value hierarchy. Key assumptions include (1) natural gas and crude oil prices (adjusted to quality and basis differentials), (2) projections of estimated quantities of oil and gas reserves and production, (3) estimates of future development and

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operating costs and (4) risk adjusted discount rates (14% at September 30, 2010). Fair value of drilling and service equipment was determined using the market approach which considered broker quotes from market participants in the oil field services sector.

Divestitures

The Company recognized an aggregate gain on sale of assets of $50.6 million, $63.4 million and $106.3 million for the years ended December 31, 2012, 2011 and 2010, respectively.

In December 2012, the Company sold certain proved oil and gas properties located in south Texas to a private company for $29.9 million, subject to post closing adjustments, and recognized an $18.2 million loss on sale of assets.

In June 2012, the Company sold a 35% non-operated working interest associated with certain of its Pearsall Shale undeveloped leaseholds in south Texas to a wholly owned subsidiary of Osaka Gas Co., Ltd. (Osaka) for total consideration of approximately $251.0 million. The Company received $125.0 million in cash proceeds and Osaka agreed to fund 85% of the Company's share of future drilling and completion costs associated with these leaseholds until it has paid approximately $126.0 million in accordance with a joint development agreement entered into at closing. The drilling and completion carry will terminate two years after the closing of the transaction. The Company recognized a $67.0 million gain on sale of assets associated with this sale.

In 2012, the Company also sold various other unproved properties and other assets for total proceeds of $14.4 million and recognized an aggregate gain of $1.8 million.

In October 2011, the Company sold certain proved oil and gas properties located in Colorado, Utah and Wyoming to Breitburn Operating L.P., a wholly owned subsidiary of Breitburn Energy Partners L.P. for $285.0 million. The Company received $283.2 million in cash proceeds, after closing adjustments, and recognized a $4.2 million gain on sale of assets.

In May 2011, the Company sold certain of its unproved Haynesville and Bossier Shale oil and gas properties in east Texas to a third party. The Company received approximately $47.0 million in cash proceeds and recognized a $34.2 million gain on sale of assets.

In February and April 2011, respectively, the Company entered into two participation agreements with third parties related to certain of its Haynesville and Bossier Shale leaseholds in east Texas. Under the terms of the participation agreements, the third parties agreed to fund 100% of the cost to drill and complete certain Haynesville and Bossier Shale wells in the related leaseholds over a multi-year period in exchange for a 75% working interest in the leaseholds. During 2011, the Company received a reimbursement of drilling costs incurred of approximately $12.9 million associated with wells that had commenced drilling prior to the execution of the participation agreements.

In 2011, the Company also sold various other unproved properties and other assets for total proceeds of $73.5 million and recognized an aggregate gain of $25.0 million.

In December 2010, the Company sold its existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations to Williams Field Services (Williams), a subsidiary of Williams Partners L.P., for $150 million and recognized a $49.3 million gain on sale of assets, which included the accrual of $17.9 million related to certain obligations that were required under the terms of the purchase and sale agreement.

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2. Properties and Equipment, Net (Continued)

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

In 2010, the Company also sold various other proved and unproved properties and other assets for total proceeds of $32.2 million and recognized an aggregate gain of $16.3 million.

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3. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |
ACCOUNTS RECEIVABLE, NET |  |  |  |  |  |  |
Trade accounts |  | $ | 165,070 |  | $ | 111,306 |
Joint interest accounts |  |  | 5,659 |  |  | 5,417 |
Other accounts |  |  | 2,817 |  |  | 1,003 |
|  |  | 173,546 |  |  | 117,726 |
Allowance for doubtful accounts |  |  | (1,127 | ) |  | (3,345 | )
|  | $ | 172,419 |  | $ | 114,381 |
INVENTORIES |  |  |  |  |  |  |
Natural gas in storage |  | $ | 7,494 |  | $ | 13,513 |
Tubular goods and well equipment |  |  | 6,392 |  |  | 7,146 |
Other accounts |  |  | 287 |  |  | 619 |
|  | $ | 14,173 |  | $ | 21,278 |
OTHER CURRENT ASSETS |  |  |  |  |  |  |
Prepaid balances and other |  | $ | 2,158 |  | $ | 2,345 |
Restricted cash |  |  | — |  |  | 2,234 |
|  | $ | 2,158 |  | $ | 4,579 |
OTHER ASSETS |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 10,608 |  | $ | 10,838 |
Debt issuance cost |  |  | 17,420 |  |  | 17,680 |
Equity method investment |  |  | 6,915 |  |  | — |
Other accounts |  |  | 83 |  |  | 1,342 |
|  | $ | 35,026 |  | $ | 29,860 |
ACCOUNTS PAYABLE |  |  |  |  |  |  |
Trade accounts |  | $ | 22,977 |  | $ | 18,253 |
Natural gas purchases |  |  | 4,892 |  |  | 3,012 |
Royalty and other owners |  |  | 66,321 |  |  | 48,113 |
Accrued capital costs |  |  | 164,862 |  |  | 138,122 |
Taxes other than income |  |  | 1,284 |  |  | 2,076 |
Drilling advances |  |  | 44,203 |  |  | 1,489 |
Producer gas imbalances |  |  | 1,602 |  |  | 2,312 |
Other accounts |  |  | 6,339 |  |  | 3,917 |
|  | $ | 312,480 |  | $ | 217,294 |
ACCRUED LIABILITIES |  |  |  |  |  |  |
Employee benefits |  | $ | 16,011 |  | $ | 26,035 |
Pension and postretirement benefits |  |  | 1,304 |  |  | 6,331 |
Taxes other than income |  |  | 8,735 |  |  | 12,297 |
Interest payable |  |  | 22,329 |  |  | 24,701 |
Derivative contracts |  |  | 192 |  |  | 385 |
Other accounts |  |  | 1,218 |  |  | 1,169 |
|  | $ | 49,789 |  | $ | 70,918 |
OTHER LIABILITIES |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 23,893 |  | $ | 20,187 |
Other accounts |  |  | 16,282 |  |  | 11,752 |
|  | $ | 40,175 |  | $ | 31,939 |

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4. Debt and Credit Agreements

The Company's debt consisted of the following:

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |
Long-Term Debt |  |  |  |  |  |  |
7.33% weighted-average fixed rate notes |  | $ | 95,000 |  | $ | 95,000 |
6.51% weighted-average fixed rate notes |  |  | 425,000 |  |  | 425,000 |
9.78% notes |  |  | 67,000 |  |  | 67,000 |
5.58% weighted-average fixed rate notes |  |  | 175,000 |  |  | 175,000 |
Credit facility |  |  | 325,000 |  |  | 188,000 |
Current Maturities |  |  |  |  |  |  |
7.33% weighted-average fixed rate notes |  |  | (75,000 | ) |  | — |
Long-Term Debt, excluding Current Maturities |  | $ | 1,012,000 |  | $ | 950,000 |

The Company has debt maturities of $75.0 million due in 2013, $20.0 million in 2016 and $245.0 million due in 2018. In addition, the revolving credit facility (credit facility) matures in 2017. No other tranches of debt are due within the next five years.

At December 31, 2012, the Company was in compliance with all restrictive financial covenants in both the revolving credit agreement and senior notes.

7.33% Weighted-Average Fixed Rate Notes

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

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

Interest on each series of the 7.33% weighted-average fixed rate notes is payable semi-annually. The Company may prepay all or any portion of the Notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The Notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. Those covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) of at least 1.75 to 1.0 (as amended) and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

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

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4. Debt and Credit Agreements (Continued)

6.51% Weighted-Average Fixed Rate Notes

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

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

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

9.78% Notes

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

5.58% Weighted-Average Fixed Rate Notes

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

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

Interest on each series of the 5.58% weighted-average fixed rate notes is payable semi-annually. The Company may prepay all or any portion of the Notes of each series on any date at a price equal to the principal amount thereof plus accrued and unpaid interest plus a make-whole premium. The other terms of the Notes are substantially similar to the terms of the 6.51% Weighted-Average Fixed Rate Notes.

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4. Debt and Credit Agreements (Continued)

Revolving Credit Agreement

In September 2010, the Company amended and restated its revolving credit facility. The Company subsequently amended the revolving credit facility in May 2012 to adjust the margins associated with borrowings under the facility and extended the maturity date from September 2015 to May 2017. The credit facility, as amended, provides for an available credit line of $900 million with an accordion feature, which allows the Company to increase the available credit line by an additional $500 million if one or more of the existing or new banks agree to provide such increased amount. The other terms and conditions of the amended facility are generally consistent with the terms and conditions of the September 2010 credit agreement prior to its amendment.

In conjunction with entering into the May 2012 amendment, the Company incurred $5.0 million of debt issuance costs, which were capitalized and will be amortized over the term of the amended credit facility. Approximately $1.3 million of unamortized cost associated with the original credit facility was recognized as a debt extinguishment cost, which was included in Interest expense and other in the Consolidated Statement of Operations, and the remaining unamortized costs of $11.0 million will be amortized over the term of the amended credit facility.

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

The Borrowing Base is redetermined annually under the terms of the credit facility on April 1. In addition, either the Company or the banks may request an interim redetermination twice a year in connection with certain acquisitions or sales of oil and gas properties. As of December 31, 2012, the Company's borrowing base was $1.7 billion.

Interest rates under the amended credit facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin. The associated margins increase if the total indebtedness under the credit facility and the Company's senior notes as a percentage of the Borrowing Base is greater than the percentages shown below:

|  | Debt Percentage
--- | --- | ---
|  | <25% |  | ³25% <50% |  | ³50% <75% |  | ³75% <90% |  | ³90%
Eurodollar loans |  | 1.50% |  | 1.75% |  | 2.00% |  | 2.25% |  | 2.50%
ABR loans |  | 0.50% |  | 0.75% |  | 1.00% |  | 1.25% |  | 1.50%

The amended credit facility provides for a commitment fee on the unused available balance at annual rates ranging from 0.375% to 0.50%.

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

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

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4. Debt and Credit Agreements (Continued)

(b)
  Maintenance of an asset coverage ratio of the present value of proved reserves plus working capital to debt of 1.75 to 1.0.
(c)
  Maintenance of a current ratio of 1.0 to 1.0.
(d)
  Prohibition on the merger or sale of all or substantially all of the Company's or any subsidiary's assets to a third party, except under certain limited conditions.

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

At December 31, 2012 and 2011, borrowings outstanding under the Company's credit facility were $325.0 million and $188.0 million, respectively. Availability under the credit facility at December 31, 2012 was $574.0 million.

The Company's weighted-average effective interest rates for the credit facility during the years ended December 31, 2012, 2011 and 2010 were approximately 3.0%, 4.1% and 3.8%, respectively. As of December 31, 2012 and 2011, the weighted-average interest rate on the Company's credit facility was approximately 2.2% and 4.9%, respectively.

5. Equity Method Investment

Constitution Pipeline Company, LLC

In February 2012, the Company entered into a Precedent Agreement with Constitution Pipeline Company, LLC (Constitution), at the time a wholly owned subsidiary of Williams Partners L.P., to develop and construct a 120 mile large diameter pipeline to transport its production in northeast Pennsylvania to both the New England and New York markets. Under the terms of the Precedent Agreement, the Company will have transportation rights for up to approximately 500,000 Mcf per day of capacity on the newly constructed pipeline, subject to regulatory approval and certain terms and conditions to be determined.

In April 2012, the Company entered into an Amended and Restated Limited Liability Company Agreement (LLC Agreement) with Constitution, which thereby became an unconsolidated investee. Under the terms of the LLC Agreement, the Company acquired a 25% equity interest and agreed to invest its proportionate share of costs associated with the development and construction of the pipeline and related facilities, subject to a contribution cap of $250 million, which is expected to occur over approximately four years.

During 2012, the Company made contributions of $6.9 million to fund costs associated with the project. The Company's net book value in this equity investment was $6.9 million as of December 31, 2012 and is included in Other assets in the Consolidated Balance Sheet. There were no material earnings or losses associated with Constitution during 2012. Earnings (losses) on equity method investment are included in Interest expense and other in the Consolidated Statement of Operations.

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6. Employee Benefit Plans

Pension Plan

Prior to its termination in 2010, the Company had a non-contributory, defined benefit pension plan for all full-time employees, referred to as the tax qualified defined benefit pension plan (qualified pension plan). Plan benefits were based primarily on years of service and salary level near retirement. During the existence of the plan, the Company complied with the Employee Retirement Income Security Act (ERISA) of 1974 and Internal Revenue Code limitations when funding the plan. The Company also had an unfunded non-qualified supplemental pension plan to ensure payments to certain executive officers of amounts to which they would have been entitled under the provisions of the pension plan, but for limitations imposed by federal tax laws, referred to as the supplemental non-qualified pension arrangements (non-qualified pension plan).

Termination and Amendment of Qualified and Non-Qualified Pension Plans

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

On March 14, 2012, the Internal Revenue Service provided the Company with a favorable determination letter for the termination of the Company's qualified pension plan. During 2012, the Company contributed $11.3 million to its qualified plan to fund the liquidation of the trust under the qualified pension plan. During 2011, the Company contributed $5.6 million to its non-qualified pension plan to fund the final distribution of benefits. As of December 31, 2012 and 2011, the benefit obligations associated with the qualified and non-qualified pension plans, respectively, were fully satisfied.

Obligations and Funded Status

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

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6. Employee Benefit Plans (Continued)

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

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012(1) |  | 2011(2) |  | 2010 |
Change in Benefit Obligation |  |  |  |  |  |  |  |  |  |
Benefit obligation at beginning of year |  | $ | 49,618 |  | $ | 63,872 |  | $ | 75,092 |
Service cost |  |  | — |  |  | — |  |  | 2,774 |
Interest cost |  |  | 922 |  |  | 2,826 |  |  | 3,700 |
Actuarial loss |  |  | 7,444 |  |  | 11,835 |  |  | 9,265 |
Plan termination and amendment |  |  | — |  |  | — |  |  | (12,331 | )
Benefits paid |  |  | (50,969 | ) |  | (10,831 | ) |  | (14,628 | )
Annuities paid |  |  | (7,015 | ) |  | (18,084 | ) |  | — |
Benefit obligation at end of year |  |  | — |  |  | 49,618 |  |  | 63,872 |
Change in Plan Assets |  |  |  |  |  |  |  |  |  |
Fair value of plan assets at beginning of year |  |  | 44,548 |  |  | 60,078 |  |  | 53,180 |
Actual return on plan assets |  |  | 2,719 |  |  | (291 | ) |  | 7,095 |
Employer contributions |  |  | 11,251 |  |  | 14,332 |  |  | 15,416 |
Benefits paid |  |  | (50,969 | ) |  | (10,831 | ) |  | (14,628 | )
Annuities purchased |  |  | (7,015 | ) |  | (18,084 | ) |  | — |
Expenses paid |  |  | (534 | ) |  | (656 | ) |  | (985 | )
Fair value of plan assets at end of year(3) |  |  | — |  |  | 44,548 |  |  | 60,078 |
Funded status at end of year |  | $ | — |  | $ | (5,070 | ) | $ | (3,794 | )

(1)
  On July 13, 2012, the Company made a final distribution of benefits from the qualified pension plan.
(2)
  On December 15, 2011, the Company made a final distribution of benefits from the non-qualified pension plan.
(3)
  Plan assets consist of cash and investments in equity and debt securities. Cash held in the trust is classified as Level 1 in the fair value hierarchy. The fair value of investments in equity and debt securities is based on market quoted market prices where there are few transactions for the assets utilizing public information, independent external valuations from third-party pricing services or third-party advisors securities. Investments in both equity and debt securities are classified as Level 2 in the fair value hierarchy.

Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet consist of the following:

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Current liabilities |  | $ | — |  | $ | 5,070 |  | $ | 603 |
Long-term liabilities |  |  | — |  |  | — |  |  | 3,191 |
|  | $ | — |  | $ | 5,070 |  | $ | 3,794 |

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6. Employee Benefit Plans (Continued)

Amounts Recognized in Accumulated Other Comprehensive Income

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

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Prior service cost |  | $ | — |  | $ | 221 |  | $ | 1,267 |
Net actuarial loss |  |  | — |  |  | 13,082 |  |  | 12,248 |
|  | $ | — |  | $ | 13,303 |  | $ | 13,515 |

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

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012(1) |  | 2011(2) |  | 2010 |
Components of Net Periodic Benefit Cost |  |  |  |  |  |  |  |  |  |
Current year service cost |  | $ | — |  | $ | — |  | $ | 2,774 |
Interest cost |  |  | 922 |  |  | 2,826 |  |  | 3,700 |
Expected return on plan assets |  |  | (1,747 | ) |  | (4,103 | ) |  | (4,260 | )
Amortization of prior service cost |  |  | 221 |  |  | 1,046 |  |  | 572 |
Amortization of net loss |  |  | 13,082 |  |  | 10,527 |  |  | 8,705 |
Plan termination and amendment |  |  | — |  |  | — |  |  | 423 |
Settlement |  |  | 7,007 |  |  | 5,523 |  |  | 4,021 |
Net periodic pension cost |  | $ | 19,485 |  | $ | 15,819 |  | $ | 15,935 |
Other Changes in Qualified Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income |  |  |  |  |  |  |  |  |  |
Net (gain)/loss |  | $ | — |  | $ | 16,884 |  | $ | (4,523 | )
Amortization of net loss |  |  | (13,082 | ) |  | (10,527 | ) |  | (8,705 | )
Amortization of prior service cost |  |  | (221 | ) |  | (1,046 | ) |  | (572 | )
Effect of plan termination and amendment |  |  | — |  |  | — |  |  | (816 | )
Settlement |  |  | — |  |  | (5,523 | ) |  | (4,021 | )
Total recognized in other comprehensive income |  | $ | (13,303 | ) | $ | (212 | ) | $ | (18,637 | )
Total recognized in net periodic benefit cost and other comprehensive income |  | $ | 6,182 |  | $ | 15,607 |  | $ | (2,702 | )

(1)
  On July 13, 2012, the Company made a final distribution of benefits from the qualified pension plan.
(2)
  On December 15, 2011, the Company made a final distribution of benefits from the non-qualified pension plan.

Postretirement Benefits Other than Pensions

The Company provides certain health care benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. The health care plans are contributory, with participants' contributions adjusted annually.

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6. Employee Benefit Plans (Continued)

Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 265 retirees and their dependents at the end of 2012 and 275 retirees and their dependents at the end of 2011.

Obligations and Funded Status

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

The change in the Company's postretirement benefit obligation is as follows:

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Change in Benefit Obligation |  |  |  |  |  |  |  |  |  |
Benefit obligation at beginning of year |  | $ | 39,969 |  | $ | 31,947 |  | $ | 34,392 |
Service cost |  |  | 1,513 |  |  | 1,403 |  |  | 1,265 |
Interest cost |  |  | 1,537 |  |  | 1,717 |  |  | 1,696 |
Actuarial (gain) / loss |  |  | (2,073 | ) |  | 6,015 |  |  | (4,415 | )
Benefits paid |  |  | (778 | ) |  | (1,113 | ) |  | (991 | )
Benefit obligation at end of year |  | $ | 40,168 |  | $ | 39,969 |  | $ | 31,947 |
Change in Plan Assets |  |  |  |  |  |  |  |  |  |
Fair value of plan assets at end of year |  |  | — |  |  | — |  |  | — |
Funded status at end of year |  | $ | (40,168 | ) | $ | (39,969 | ) | $ | (31,947 | )

Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet consist of the following:

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Current liabilities |  | $ | 1,304 |  | $ | 1,261 |  | $ | 1,085 |
Long-term liabilities |  |  | 38,864 |  |  | 38,708 |  |  | 30,862 |
|  | $ | 40,168 |  | $ | 39,969 |  | $ | 31,947 |

Amounts Recognized in Accumulated Other Comprehensive Income

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

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Transition obligation |  | $ | — |  | $ | — |  | $ | 632 |
Net actuarial loss |  |  | 11,269 |  |  | 14,166 |  |  | 8,408 |
|  | $ | 11,269 |  | $ | 14,166 |  | $ | 9,040 |

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6. Employee Benefit Plans (Continued)

The estimated net actuarial loss for the defined benefit postretirement plan that will be amortized from accumulated other comprehensive income into net periodic postretirement cost over the next fiscal year is $0.8 million.

Components of Net Periodic Benefit Cost and Other Amounts Recognized in Other Comprehensive Income

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Components of Net Periodic Postretirement Benefit Cost |  |  |  |  |  |  |  |  |  |
Current year service cost |  | $ | 1,513 |  | $ | 1,403 |  | $ | 1,265 |
Interest cost |  |  | 1,537 |  |  | 1,717 |  |  | 1,696 |
Amortization of net obligation at transition |  |  | — |  |  | 632 |  |  | 632 |
Amortization of net loss |  |  | 824 |  |  | 448 |  |  | 631 |
Net periodic postretirement cost |  | $ | 3,874 |  | $ | 4,200 |  | $ | 4,224 |
Other Changes in Benefit Obligations Recognized in Other Comprehensive Income |  |  |  |  |  |  |  |  |  |
Net (gain) / loss |  | $ | (2,073 | ) | $ | 6,015 |  | $ | (4,415 | )
Amortization of net obligation at transition |  |  | — |  |  | (632 | ) |  | (632 | )
Amortization of net loss |  |  | (824 | ) |  | (448 | ) |  | (631 | )
Total recognized in other comprehensive income |  |  | (2,897 | ) |  | 4,935 |  |  | (5,678 | )
Total recognized in net periodic benefit cost and other comprehensive income |  | $ | 977 |  | $ | 9,135 |  | $ | (1,454 | )

Assumptions

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

|  | December 31, |
--- | --- | --- | ---
|  | 2012 |  | 2011 |  | 2010 |
Discount rate(1) |  |  | 4.00% |  |  | 4.25% |  |  | 5.75% |
Health care cost trend rate for medical benefits assumed for next year |  |  | 7.00% |  |  | 8.00% |  |  | 9.00% |
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) |  |  | 5.00% |  |  | 5.00% |  |  | 5.00% |
Year that the rate reaches the ultimate trend rate |  |  | 2015 |  |  | 2015 |  |  | 2015 |

(1)
  Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2012, 2011 and 2010, respectively, the beginning of year discount rates of 4.25%, 5.75% and 5.75% were used.

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

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6. Employee Benefit Plans (Continued)

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

(In thousands) |  | 1-Percentage- Point Increase |  | 1-Percentage- Point Decrease |
--- | --- | --- | --- | --- | ---
Effect on total of service and interest cost |  | $ | 588 |  | $ | (470 | )
Effect on postretirement benefit obligation |  |  | 6,451 |  |  | 5,241 |

Cash Flows

Contributions

The Company expects to contribute approximately $1.3 million to the postretirement benefit plan in 2013.

Estimated Future Benefit Payments

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

(In thousands) |  |  |
--- | --- | --- | ---
2013 |  | $ | 1,330 |
2014 |  |  | 1,465 |
2015 |  |  | 1,568 |
2016 |  |  | 1,665 |
2017 |  |  | 1,772 |
Years 2018 - 2022 |  |  | 11,372 |

Savings Investment Plan

The Company has a Savings Investment Plan (SIP), which is a defined contribution plan. The Company matches a portion of employees' contributions in cash. Participation in the SIP is voluntary, and all regular employees of the Company are eligible to participate. The Company made contributions of $2.5 million, $2.0 million and $2.2 million in 2012, 2011 and 2010, respectively, which are included in General and administrative expense in the Consolidated Statement of Operations. The Company matches employee contributions dollar-for-dollar, up to the maximum IRS limit, on the first six percent of an employee's pretax earnings. The Company's common stock is an investment option within the SIP.

In July 2010, the Company amended the SIP to provide for discretionary profit sharing contributions upon termination of the qualified pension plan effective September 30, 2010. The Company presently makes a discretionary profit- sharing contribution to this plan in an amount equal to 9% of an eligible plan participant's salary and bonus. The Company charged to expense plan contributions of $3.9 million, $3.6 million and $0.8 million in 2012, 2011 and 2010, respectively, which are included in General and administrative expense in the Consolidated Statement of Operations.

Deferred Compensation Plan

The Company has a Deferred Compensation Plan which is available to officers and certain members of the Company's management group and acts as a supplement to the SIP. The Internal Revenue Code does not cap the amount of compensation that may be taken into account for purposes

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of determining contributions to the Deferred Compensation Plan and does not impose limitations on the amount of contributions to the Deferred Compensation Plan. At the present time, the Company anticipates making a contribution to the Deferred Compensation Plan on behalf of a participant in the event that Internal Revenue Code limitations cause a participant to receive less than the Company matching contribution under the SIP.

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

Under the Deferred Compensation Plan, the participants direct the deemed investment of amounts credited to their accounts. The trust assets are invested in either mutual funds that cover the investment spectrum from equity to money market, or may include holdings of the Company's common stock, which is funded by the issuance of shares to the trust. The mutual funds are publicly traded and have market prices that are readily available. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets, excluding the Company's common stock, was $10.6 million and $10.8 million at December 31, 2012 and 2011, respectively, and is included in Other assets in the Consolidated Balance Sheet. Related liabilities, including the Company's common stock, totaled $23.9 million and $20.2 million at December 31, 2012 and 2011, respectively, and are included in Other liabilities in the Consolidated Balance Sheet. With the exception of the Company's common stock, there is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets because the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants.

The Company's common stock held in the rabbi trust is recorded at the market value on the date of deferral, which totaled $5.7 million and $4.9 million at December 31, 2012 and 2011, respectively and is included in Additional paid-in capital in Stockholders' Equity in the Consolidated Balance Sheet. As of December 31, 2012, 267,087 shares of the Company's stock representing vested performance share awards were deferred into the rabbi trust. During 2012, the Company recognized $3.2 million in General and administrative expense in the Consolidated Statement of Operations representing the increase in the closing price of the Company's shares held in the trust. The Company's common stock issued to the trust is not considered outstanding for purposes of calculating basic earnings per share, but is considered a common stock equivalent in the calculation of diluted earnings per share.

The Company charged to expense plan contributions of $661,676, $522,807 and $109,196 in 2012, 2011 and 2010, respectively, which are included in General and administrative expense in the Consolidated Statement of Operations.

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7. Income Taxes

Income tax expense is summarized as follows:

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Current |  |  |  |  |  |  |  |  |  |
Federal |  | $ | 24,618 |  | $ | 39,749 |  | $ | 29,879 |
State |  |  | 563 |  |  | (1,714 | ) |  | 3,424 |
Total |  |  | 25,181 |  |  | 38,035 |  |  | 33,303 |
Deferred |  |  |  |  |  |  |  |  |  |
Federal |  |  | 57,704 |  |  | 46,599 |  |  | 37,981 |
State |  |  | 23,225 |  |  | 28,145 |  |  | 23,828 |
Total |  |  | 80,929 |  |  | 74,744 |  |  | 61,809 |
Total income tax expense |  | $ | 106,110 |  | $ | 112,779 |  | $ | 95,112 |

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

|  | Year Ended December 31, |
--- | --- | --- | ---
(Dollars in thousands) |  | 2012 |  | 2011 |  | 2010 |
Statutory federal income tax rate |  |  | 35% |  |  | 35% |  |  | 35% |
Computed "expected" federal income tax |  | $ | 83,244 |  | $ | 82,316 |  | $ | 69,475 |
State income tax, net of federal income tax benefit |  |  | 9,609 |  |  | 8,989 |  |  | 6,638 |
Deferred tax adjustment related to change in overall state tax rate |  |  | 13,596 |  |  | 19,068 |  |  | 18,973 |
Other, net |  |  | (339 | ) |  | 2,406 |  |  | 26 |
Total income tax expense |  | $ | 106,110 |  | $ | 112,779 |  | $ | 95,112 |

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

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |
Deferred Tax Liabilities |  |  |  |  |  |  |
Property, plant and equipment |  | $ | 1,204,735 |  | $ | 1,068,762 |
Hedging liabilities / receivables |  |  | 19,915 |  |  | 68,670 |
Prepaid expenses and other |  |  | 736 |  |  | 9,261 |
Total |  |  | 1,225,386 |  |  | 1,146,693 |
Deferred Tax Assets |  |  |  |  |  |  |
Alternative minimum tax credit |  |  | 125,862 |  |  | 101,290 |
Net operating loss |  |  | 137,422 |  |  | 113,496 |
Foreign tax credits |  |  | 4,923 |  |  | 4,685 |
Pension and other post-retirement benefits |  |  | 16,498 |  |  | 19,892 |
Items accrued for financial reporting purposes and other |  |  | 52,806 |  |  | 49,606 |
Total |  |  | 337,511 |  |  | 288,969 |
Net deferred tax liabilities |  | $ | 887,875 |  | $ | 857,724 |

As of December 31, 2012, the Company had alternative minimum tax credit carryforwards of $125.9 million which do not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the alternative minimum tax in any such year. The Company also had net operating loss carryforwards of $398.6 million and $378.2 million for federal and state reporting purposes, respectively, the majority of which will expire between 2016 and 2032. The Company believes it is more likely than not that these deferred tax benefits will be utilized prior to their expiration. Tax benefits related to employee stock-based compensation included in net operating loss carryforwards but not reflected in deferred tax assets as of December 31, 2012 are approximately $66.9 million.

Uncertain Tax Positions

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

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Unrecognized tax benefit balance at beginning of year |  | $ | — |  | $ | — |  | $ | 500 |
Additions based on tax provisions related to the current year |  |  | — |  |  | — |  |  | — |
Additions for tax positions of prior years |  |  | — |  |  | — |  |  | — |
Reductions for tax positions of prior years |  |  | — |  |  | — |  |  | (500 | )
Settlements |  |  | — |  |  | — |  |  | — |
Unrecognized tax benefit balance at end of year |  | $ | — |  | $ | — |  | $ | — |

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

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December 31, 2012 and 2011, the Company did not have any uncertain tax positions reported in the Consolidated Balance Sheet.

The Company files income tax returns in the U.S. federal jurisdiction, various states and other jurisdictions. The Company is no longer subject to examinations by state authorities before 2008. The Company is not currently under examination by the IRS.

8. Commitments and Contingencies

Transportation Agreements

The Company has entered into certain natural gas and liquids transportation agreements with various pipelines with initial terms ranging from approximately four to 23 years. Under certain of these agreements, the Company is obligated to transport minimum daily quantities, or pay for any deficiencies at a specified rate. The Company is also obligated under certain of these arrangements to pay a demand charge for firm capacity rights on pipeline systems regardless of the amount of pipeline capacity utilized by the Company. In most cases, the Company's production commitment to these pipelines is expected to exceed minimum daily quantities provided in the agreements. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability.

Future obligations under transportation agreements as of December 31, 2012 are as follows:

(In thousands) |  |  |
--- | --- | --- | ---
2013 |  | $ | 94,714 |
2014 |  |  | 98,145 |
2015 |  |  | 115,203 |
2016 |  |  | 126,973 |
2017 |  |  | 121,923 |
Thereafter |  |  | 1,156,294 |
|  | $ | 1,713,252 |

Drilling Rig Commitments

During 2012, the Company did not enter into any new long-term drilling rig commitments. The existing commitments that commenced in the fourth quarter of 2011 relate to the Company's capital program in the Marcellus Shale and have original terms ranging from two to three years. The future minimum commitments under these agreements as of December 31, 2012 are $17.9 million in 2013 and $9.2 million in 2014.

Lease Commitments

The Company leases certain office space, warehouse facilities, vehicles, and machinery and equipment under cancelable and non-cancelable leases. Rent expense under these arrangements totaled $11.6 million, $13.6 million and $18.3 million for the years ended December 31, 2012, 2011 and 2010, respectively.

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8. Commitments and Contingencies (Continued)

Future minimum rental commitments under non-cancelable leases in effect at December 31, 2012 are as follows:

(In thousands) |  |  |
--- | --- | --- | ---
2013 |  | $ | 5,106 |
2014 |  |  | 4,652 |
2015 |  |  | 3,624 |
2016 |  |  | 730 |
2017 |  |  | 192 |
Thereafter |  |  | — |
|  | $ | 14,304 |

Legal Matters

Preferential Purchase Right Litigation

In September 2005, the Company and Linn Energy, LLC were sued by Power Gas Marketing & Transmission, Inc. in the Court of Common Pleas of Indiana County, Pennsylvania. The lawsuit seeks unspecified damages arising out of the Company's 2003 sale of oil and gas properties located in Indiana County, Pennsylvania, to Linn Energy, LLC. The plaintiff alleges breach of a preferential purchase right regarding those properties contained in a 1969 joint operating agreement to which the plaintiff was a party. The Company initially obtained judgment as a matter of law as to all claims in a decision by the trial court dated February 2007. Plaintiff appealed the ruling to the Pennsylvania Superior Court, where the ruling in favor of the Company was reversed and remanded to the trial court in March 2008. The Company appealed the Superior Court ruling to the Pennsylvania Supreme Court, but in December 2008 that Court declined to review. Effective July 2008, Linn Energy, LLC sold the subject properties to XTO Energy, Inc., giving rise to a second lawsuit for unspecified damages filed in September 2009 by EXCO—North Coast Energy, Inc., as successor in interest to Power Gas Marketing & Transmission, Inc., against the Company, Linn Energy, LLC and XTO Energy, Inc. The second lawsuit has been consolidated into the first lawsuit. A bench trial was held in early June 2012 and closing arguments were held in January 2013, but there has not yet been a final ruling on the case.

The Company believes that the plaintiff's claims lack merit and does not consider a loss related to this matter to be probable; however, due to the inherent uncertainties of litigation, a loss is possible. In the event that the Company is found liable, the potential loss is currently estimated to be less than $15 million.

Other

The Company is also a defendant in various other legal proceedings arising in the normal course of business. All known liabilities are accrued based on management's best estimate of the potential loss. While the outcome and impact of these legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings will not have a material effect on the Company's financial position, results of operations or cash flows.

Contingency Reserves

When deemed necessary, the Company establishes reserves for certain legal proceedings. The establishment of a reserve is based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it

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is reasonably possible that the Company could incur additional losses with respect to those matters in which reserves have been established. The Company believes that any such amount above the amounts accrued is not material to the Consolidated Financial Statements. Future changes in facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

Environmental Matters

Pennsylvania Department of Environmental Protection

On December 15, 2010, the Company entered into a consent order and settlement agreement (CO&SA) with the Pennsylvania Department of Environmental Protection (PaDEP), addressing a number of environmental issues originally identified in 2008 and 2009, including alleged releases of drilling mud and other substances, alleged record keeping violations at various wells and alleged natural gas contamination of water supplies to 14 households in Susquehanna County, Pennsylvania. During 2010 and 2011, the Company paid a total of $1.3 million in settlement of fines and penalties sought or claimed by the PaDEP related to this matter. On January 11, 2011, certain of the affected households appealed the CO&SA to the Pennsylvania Environmental Hearing Board (PEHB). On October 17, 2011, the Company requested PaDEP approval to resume hydraulic fracturing and new natural gas well drilling operations in the affected area, along with a request to cease temporary water deliveries to the affected households pursuant to prior consent orders with the PaDEP. The PaDEP concurred that temporary water deliveries to the property owners are no longer necessary. On November 18, 2011, certain of the affected households appealed this order to the PEHB, which appeal was later consolidated with the CO&SA appeal. All appellants have accepted their portion of the $2.2 million that was placed into escrow in 2011 for their benefit and on October 18, 2012 dismissed their appeal to the PEHB. Subsequent to the withdrawal of the appeals, the PEHB allowed three of the appellants to reinstate their appeal. A hearing related to the reinstated appeal is expected to occur in the first half 2013.

The Company is in continuing discussions with the PaDEP to address the results of the Company's natural gas well test data, water quality sampling and water well headspace screenings, which were required pursuant to the CO&SA. On August 21, 2012, the PaDEP notified the Company that it could commence completion operations on existing wells within the concerned area.

9. Asset Retirement Obligation

Activity related to the Company's asset retirement obligation during the year ended December 31, 2012 is as follows:

(In thousands) |  |  |
--- | --- | --- | ---
Balance at December 31, 2011 |  | $ | 60,142 |
Liabilities incurred |  |  | 2,685 |
Liabilities settled |  |  | (1,259 | )
Liabilities divested |  |  | (4,463 | )
Accretion expense |  |  | 3,165 |
Change in Estimate |  |  | 6,746 |
Balance at December 31, 2012 |  | $ | 67,016 |

The change in estimate during 2012 is attributable to increased costs for materials and services to plug and abandon wells in certain areas of our operations.

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10. Supplemental Cash Flow Information

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

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Interest |  | $ | 64,970 |  | $ | 62,353 |  | $ | 64,342 |
Income taxes |  |  | 22,501 |  |  | 65,352 |  |  | (1,050 | )

11. Capital Stock

Incentive Plans

Under the Company's 2004 Incentive Plan, incentive and non-statutory stock options, stock appreciation rights (SARs), stock awards, cash awards and performance awards may be granted to key employees, consultants and officers of the Company. Non-employee directors of the Company may be granted discretionary awards under the 2004 Incentive Plan consisting of stock options or stock awards. A total of 10,200,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than 3,600,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 6,000,000 shares may be issued pursuant to incentive stock options.

Increase in Authorized Shares

In May 2012, the stockholders of the Company approved an increase in the authorized number of shares of common stock from 240 million to 480 million shares.

Treasury Stock

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

During the years ended December 31, 2012, 2011 and 2010, the Company did not repurchase any shares of common stock. Since the authorization date, the Company has repurchased 10,409,400 shares of the 20 million total shares authorized for a total cost of approximately $85.7 million. The repurchased shares were held as treasury stock with 10,005,000 shares having been subsequently retired. No treasury shares have been delivered or sold by the Company subsequent to the repurchase. As of December 31, 2012, 404,400 shares were held as treasury stock.

Dividend Restrictions

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

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12. Stock-Based Compensation

Compensation expense for stock-based awards for the years ended December 31, 2012, 2011 and 2010 was $33.5 million, $39.5 million and $14.4 million, respectively, and is included in General and administrative expense in the Consolidated Statement of Operations.

Restricted Stock Awards

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

The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is four years. The Company accelerated the vesting period for retirement-eligible employees for purposes of recognizing compensation expense in accordance with the vesting provisions of the Company's stock-based compensation programs. The Company used an annual forfeiture rate assumption ranging from 6.0% to 7.0% for purposes of recognizing stock-based compensation expense for restricted stock awards. The annual forfeiture rates were based on approximately 10 years of the Company's history for this type of award to various employee groups.

The following table is a summary of restricted stock award activity for the year ended December 31, 2012:

Restricted Stock Awards |  | Shares |  | Weighted- Average Grant Date Fair Value per Share |  | Weighted- Average Remaining Contractual Term (in years) |  | Aggregate Intrinsic Value (in thousands)(1) |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Outstanding at December 31, 2011 |  |  | 238,194 |  | $ | 18.35 |  |  |  |  |  |  |
Granted |  |  | 6,550 |  |  | 36.84 |  |  |  |  |  |  |
Vested |  |  | (201,400 | ) |  | 18.05 |  |  |  |  |  |  |
Forfeited |  |  | (7,590 | ) |  | 17.60 |  |  |  |  |  |  |
Outstanding at December 31, 2012 |  |  | 35,754 |  | $ | 23.64 |  |  | 0.8 |  | $ | 1,778 |

(1)
  The aggregate intrinsic value of restricted stock awards is calculated by multiplying the closing market price of the Company's stock on December 31, 2012 by the number of non-vested restricted stock awards outstanding.

During the year ended December 31, 2011, 19,600 shares of restricted stock were granted to employees with a weighted-average grant date fair value per share of $27.66. During the year ended December 31, 2010, 47,600 shares of restricted stock were granted to employees with a weighted- average grant date fair value per share of $17.44. The total fair value of shares vested during 2012, 2011 and 2010 was $3.6 million, $0.2 million and $1.5 million, respectively.

Compensation expense recorded for all restricted stock awards for the years ended December 31, 2012, 2011 and 2010 was $1.1 million, $1.2 million and $1.8 million, respectively. Unamortized expense

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as of December 31, 2012 for all outstanding restricted stock awards was $0.3 million and will be recognized over the next 1.1 years.

Restricted Stock Units

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

The following table is a summary of restricted stock unit activity for the year ended December 31, 2012:

Restricted Stock Units |  | Units |  | Weighted- Average Grant Date Fair Value per Unit |  | Weighted- Average Remaining Contractual Term (in years)(2) |  | Aggregate Intrinsic Value (in thousands)(1) |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Outstanding at December 31, 2011 |  |  | 343,654 |  | $ | 15.75 |  |  |  |  |  |  |
Granted and fully vested |  |  | 38,304 |  |  | 36.55 |  |  |  |  |  |  |
Issued |  |  | (124,224 | ) |  | 17.11 |  |  |  |  |  |  |
Forfeited |  |  | — |  |  | — |  |  |  |  |  |  |
Outstanding at December 31, 2012 |  |  | 257,734 |  | $ | 18.19 |  |  | — |  | $ | 12,820 |

(1)
  The aggregate intrinsic value of restricted stock units is calculated by multiplying the closing market price of the Company's stock on December 31, 2012 by the number of outstanding restricted stock units.
(2)
  Due to the immediate vesting of the units and the unknown term of each director, the weighted-average remaining contractual term in years has been omitted from the table above.

During 2011, 59,402 restricted stock units were granted with a weighted-average grant date fair value per share of $20.88. During 2010, 53,922 restricted stock units were granted with a weighted-average grant date fair value per share of $20.04.

During the years ended December 31, 2012, 2011 and 2010, compensation cost recorded, which reflects the total fair value of these units, was $1.4 million, $1.2 million and $1.1 million, respectively.

Stock Options

Stock options are no longer granted by the Company. In prior years, stock option awards were granted on an annual basis with an exercise price equal to the average of the high and low trading price of the Company's stock at the date of grant. During the years ended December 31, 2012, 2011 and 2010, there were no stock options granted. During 2012, 2011 and 2010 there was no compensation expense recorded. There was no unamortized expense as of December 31, 2012 for stock options.

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The following table is a summary of stock option activity:

|  | Year Ended December 31, |
--- | --- | --- | ---
|  | 2012 |  | 2011 |  | 2010 |
Stock Options |  | Shares |  | Weighted- Average Exercise Price |  | Shares |  | Weighted- Average Exercise Price |  | Shares |  | Weighted- Average Exercise Price |
Outstanding at beginning of year |  |  | — |  | $ | — |  |  | 30,000 |  | $ | 11.90 |  |  | 100,000 |  | $ | 11.90 |
Granted |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Exercised |  |  | — |  |  | — |  |  | (30,000 | ) |  | 11.90 |  |  | (70,000 | ) |  | 11.90 |
Forfeited or expired |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Outstanding at December 31 |  |  | — |  | $ | — |  |  | — |  | $ | — |  |  | 30,000 |  | $ | 11.90 |
Options exercisable at December 31 |  |  | — |  | $ | — |  |  | — |  | $ | — |  |  | 30,000 |  | $ | 11.90 |

The total intrinsic value of options exercised during the years ended December 31, 2011 and 2010 was $0.2 million and $0.5 million, respectively.

Stock Appreciation Rights

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

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

|  | Year Ended December 31, |
--- | --- | --- | ---
|  | 2012 |  | 2011 |  | 2010 |
Weighted-average value per stock appreciation rights Granted during the period |  | $ | 16.31 |  | $ | 9.47 |  | $ | 9.48 |
Assumptions |  |  |  |  |  |  |  |  |  |
Stock price volatility |  |  | 55.3% |  |  | 52.7% |  |  | 52.9% |
Risk free rate of return |  |  | 0.9% |  |  | 2.3% |  |  | 2.4% |
Expected dividend yield |  |  | 0.3% |  |  | 0.3% |  |  | 0.3% |
Expected term (in years) |  |  | 5.0 |  |  | 5.0 |  |  | 5.0 |

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

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The following is a summary of SAR activity:

|  | Year Ended December 31, |
--- | --- | --- | ---
|  | 2012 |  | 2011 |  | 2010 |
Stock Appreciation Rights |  | Shares |  | Weighted- Average Exercise Price |  | Shares |  | Weighted- Average Exercise Price |  | Shares |  | Weighted- Average Exercise Price |
Outstanding at Beginning of Year |  |  | 1,288,130 |  | $ | 16.04 |  |  | 1,471,300 |  | $ | 15.27 |  |  | 1,346,200 |  | $ | 14.64 |
Granted |  |  | 120,442 |  |  | 35.18 |  |  | 191,500 |  |  | 20.37 |  |  | 159,100 |  |  | 20.27 |
Exercised |  |  | (547,350 | ) |  | 14.84 |  |  | (374,670 | ) |  | 15.22 |  |  | (34,000 | ) |  | 13.58 |
Forfeited or expired |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Outstanding at December 31(1) |  |  | 861,222 |  | $ | 19.49 |  |  | 1,288,130 |  | $ | 16.04 |  |  | 1,471,300 |  | $ | 15.27 |
Exercisable at December 31(2) |  |  | 572,986 |  | $ | 15.94 |  |  | 902,664 |  | $ | 15.14 |  |  | 1,064,444 |  | $ | 14.82 |

(1)
  The intrinsic value of a SAR is the amount which the current market value of the underlying stock exceeds the exercise price of the SAR. The aggregate intrinsic value of SARs outstanding at December 31, 2012 was $26.1 million. The weighted-average remaining contractual term is 3.9 years.
(2)
  The aggregate intrinsic value of SARs exercisable at December 31, 2012 was $19.4 million. The weighted-average remaining contractual term is 3.1 years.

Compensation expense recorded during the years ended December 31, 2012, 2011 and 2010 for all outstanding SARs was $1.9 million, $2.1 million and $1.6 million, respectively. In 2012, 2011 and 2010 there was $1.2 million, $0.1 million and $0, related to the immediate expensing of shares granted to retirement-eligible employees, respectively. Unamortized expense as of December 31, 2012 for all outstanding SARs was $0.4 million. The weighted-average period over which this compensation will be recognized is approximately 2.0 years.

Performance Share Awards

The Company grants three types of performance share awards: two based on performance conditions measured against the Company's performance metrics and one based on market conditions measured based on the Company's performance relative to a predetermined peer group. For all performance share awards, the Company used an annual forfeiture rate assumption ranging from 0% to 7% for purposes of recognizing stock-based compensation expense. The performance period for the awards granted in 2012 commenced on January 1, 2012 and ends on December 31, 2014.

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The following table is a summary of performance share award activity for the year ended December 31, 2012:

Performance Share Awards |  | Shares |  | Weighted- Average Grant Date Fair Value per Share(1) |  | Weighted- Average Remaining Contractual Term (in years) |  | Aggregate Intrinsic Value (in thousands)(2) |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Outstanding at December 31, 2011 |  |  | 2,441,566 |  | $ | 15.31 |  |  |  |  |  |  |
Granted |  |  | 518,602 |  |  | 33.62 |  |  |  |  |  |  |
Issued and fully vested |  |  | (1,358,564 | ) |  | 11.95 |  |  |  |  |  |  |
Forfeited |  |  | (42,850 | ) |  | 24.22 |  |  |  |  |  |  |
Outstanding at December 31, 2012 |  |  | 1,558,754 |  | $ | 24.08 |  |  | 1.1 |  | $ | 77,532 |

(1)
  The fair value figures in this table represent the fair value of the equity component of the performance share awards.
(2)
  The aggregate intrinsic value of performance share awards is calculated by multiplying the closing market price of the Company's stock on December 31, 2012 by the number of non-vested performance share awards outstanding.

During the year ended December 31, 2012, 518,602 performance shares (401,141 shares based on performance conditions and 117,461 shares based on market conditions) were granted to employees. Of the 1,358,564 performance shares that vested during 2012, a total of 168,940 shares based on market conditions were granted in 2010 (valued at $2.7 million), 393,620 shares based on market conditions were granted in 2009 (valued at $3.5 million) and were issued in addition to $18.4 million that was paid in cash due to the ranking of the Company compared to its peers. A total of 594,960 shares based on performance conditions granted in 2009 (valued at $6.7 million) were also issued. In addition, 201,044 shares vested (valued at $3.3 million) which represents one-third of the three-year graded vesting schedule performance share awards based on performance conditions were granted in 2011, 2010 and 2009 with a grant date per share value of $20.37, $20.27 and $11.32, respectively.

During the year ended December 31, 2011, 789,514 performance share awards (604,122 shares based on performance conditions and 185,392 shares based on market conditions) were granted to employees with a weighted-average grant date fair value per share of $19.25. Of the 620,140 performance shares that vested during 2011, 471,744 shares were granted in 2008 (valued at $2.7 million) based on market conditions and were issued due to the ranking of the Company compared to its peers. A total of 287,600 shares based on performance conditions granted in 2008 (valued at $5.9 million) were also issued. In addition, 187,516 shares vested (valued at $3.9 million) which represents one-third of the three-year graded vesting schedule performance share awards granted in 2010, 2009 and 2008 with a grant date per share value of $20.27, $11.32 and $24.24, respectively.

During the year ended December 31, 2010, 694,340 performance share awards (525,400 shares based on performance conditions and 168,940 shares based on market conditions) were granted to employees with a weighted-average grant date fair value per share of $19.24. Of the 820,538 performance shares that vested during 2010, 184,800 shares (valued at $2.8 million) based on market conditions were granted in 2007 and were issued in addition to $1.3 million that was paid in cash due to the ranking of the Company compared to its peers. A total of 300,200 shares based on performance conditions granted in 2007 (valued at $5.3 million) were also issued. In addition, 335,538 shares vested (valued at $5.1 million) which represents one-third of the three-year graded vesting schedule

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performance share awards granted in 2009, 2008, and 2007 with a grant date per share value of $11.32, 24.24 and $17.61, respectively.

During 2012, 2011 and 2010, 42,850, 65,700 and 80,360 performance shares, respectively, were forfeited.

Total unamortized compensation cost related to the equity component of performance shares at December 31, 2012 was $12.7 million and will be recognized over the next 1.9 years, which was computed by using the weighted-average of years remaining to recognize unamortized expense. Total compensation cost recognized for both the equity and liability components of all performance share awards during the years ended December 31, 2012, 2011 and 2010 was $24.6 million, $28.5 million and $12.4 million, respectively.

Awards Based on Performance Conditions

The performance awards granted in 2012 based on internal metrics had a grant date per share value of $35.18, which is based on the average of the high and low stock price on the grant date. These awards represent the right to receive up to 100% of the award in shares of common stock.

During 2012, 401,141 performance share awards were granted based on performance conditions measured against the Company's performance metrics. Of these shares, 117,461 shares have a three-year graded performance period; one-third of the shares are issued on each anniversary date following the date of grant, provided that the Company has $100 million or more of operating cash flow for the year preceding the vesting date. If the Company does not meet this metric for the applicable period, then the portion of the performance shares that would have been issued on that date will be forfeited.

For the remaining 283,380 performance awards, the actual number of shares issued at the end of the performance period will be determined based on the Company's performance against three performance criteria set by the Company's Compensation Committee. An employee will earn one-third of the award granted for each performance metric that the Company meets at the end of the performance period. These performance criteria are based on the Company's average production, average finding costs and average reserve replacement over the three year performance period.

Based on the Company's probability assessment at December 31, 2012, it is considered probable that the criteria for these awards will be met.

Awards Based on Market Conditions

The 117,461 performance shares granted during 2012 are based on market conditions and are earned, or not earned, based on the comparative performance of the Company's common stock measured against sixteen other companies in the Company's peer group over a three-year performance period. These performance shares have both an equity and liability component, with the right to receive up to the first 100% of the award in shares of common stock and the right to receive up to 100% of the value of the award in excess of the equity component in cash. The equity portion of the 2012 awards was valued on the grant date (February 16, 2012) and was not marked to market. The liability portion of the awards was valued as of December 31, 2012 on a mark-to-market basis.

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

|  | Year Ended December 31, |
--- | --- | --- | ---
|  | 2012 |  | 2011 |  | 2010 |
Fair value per performance share award granted during the period |  | $ | 28.31 |  | $ | 15.62 |  | $ | 6.50 |
Assumptions |  |  |  |  |  |  |  |  |  |
Stock price volatility |  |  | 46.7% |  |  | 62.0% |  |  | 61.8% |
Risk free rate of return |  |  | 0.4% |  |  | 1.3% |  |  | 1.4% |
Expected dividend yield |  |  | 0.2% |  |  | 0.2% |  |  | 0.3% |

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

|  | December 31,
--- | --- | ---
|  | 2012 |  | 2011 |  | 2010
Fair value per performance share award at the end of the period |  | $38.22 - $49.52 |  | $25.64 - $35.47 |  | $0.00 - $3.08
Assumptions |  |  |  |  |  |
Stock price volatility |  | 41.1% - 45.7% |  | 41.9% - 42.7% |  | 70.7% - 71.7%
Risk free rate of return |  | 0.2% - 0.3% |  | 0.1% - 0.3% |  | 0.3% - 0.4%
Expected dividend yield |  | 0.2% |  | 0.2% |  | 0.4%

The long-term liability for market condition performance share awards, included in Other liabilities in the Consolidated Balance Sheet, at December 31, 2012 and 2011 was $7.6 million and $5.6 million, respectively. The short-term liability, included in Accrued liabilities in the Consolidated Balance Sheet, at December 31, 2012 and 2011 was $0 and $10.1 million, respectively.

Other Information

On December 31, 2012, the performance period ended for two types of performance shares awarded in 2010, including 305,480 shares measured based on performance metrics of the Company and 168,940 shares measured based on market conditions. For the internal performance metric awards, the calculation of the average of the three years of the Company's three performance metrics was completed in the first quarter of 2013 and was certified by the Compensation Committee in February 2013. As the Company achieved the three performance metrics, 305,480 shares (valued at $6.2 million) were issued in February 2013, which will be reported in the first quarter of 2013 upon certification by the Compensation Committee. For the awards based on market conditions, 168,940 shares (valued at $2.7 million) were issued in addition to $8.3 million in cash due to the ranking of the Company relative to a predetermined peer group. The calculation of the award payout was certified by the Compensation Committee and payout occurred on December 31, 2012.

Deferred Performance Shares

As of December 31, 2012, 267,087 shares of the Company's common stock representing vested performance share awards were deferred into the Deferred Compensation Plan. No shares were sold

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out of the plan in 2012. During 2012, an increase to the deferred compensation liability of $3.7 million was recognized, representing an increase in the investment excluding the Company's common stock and an increase in the closing price of the Company's common stock from December 31, 2011 to December 31, 2012. The increase in stock-based compensation expense was included in General and administrative expense in the Consolidated Statement of Operations.

Supplemental Employee Incentive Plan

On May 1, 2012, the Company's Board of Directors adopted a new Supplemental Employee Incentive Plan ("Plan") to replace the previously adopted supplemental employee incentive plan that expired on June 30, 2012. There were no amounts paid under the expired plan. The Plan commenced on July 1, 2012 and is intended to provide a compensation tool tied to stock market value creation to serve as an incentive and retention vehicle for full-time, non-officer employees by providing for cash payments in the event the Company's common stock reaches a specified trading price. The Plan is accounted for as a liability award under ASC 718. The Company recognized stock-based compensation expense of $1.4 million and $1.2 million for years ended December 31, 2012 and 2011, respectively, and a benefit of $0.9 million for the year ended December 31, 2010, which is included in General and administrative expense in the Consolidated Statement of Operations.

The Plan provides for a payout if, for any 20 trading days out of any 60 consecutive trading days, the closing price per share of the Company's common stock equals or exceeds the price goal of $50 per share by June 30, 2014 (interim trigger date) or $75 per share by June 30, 2016 (final trigger date). Under the Plan, each eligible employee may receive (upon approval by the Compensation Committee) a distribution of 20% of base salary if the interim trigger is met or 50% of base salary if the final trigger is met (or an incremental 30% of base salary if the Company paid interim distributions upon achievement of the interim trigger).

In accordance with the Plan, in the event the interim or final trigger date occurs between July 1, 2012 and December 31, 2014, 25% of the total distribution will be paid immediately and the remaining 75% will be deferred and paid at a future date as described in the Plan. For final trigger dates occurring between January 1, 2015 and June 30, 2016, total distribution will be paid immediately.

The Compensation Committee can increase any of the payments as applied to any employee if desired. Any deferred portion will only be paid if the participant is employed by the Company, or has terminated employment by reason of retirement, death or disability (as provided in the Plan). Payments are subject to certain other restrictions contained in the Plan.

On February 11, 2013, the Company achieved the price goal of $50 per share prior to the interim trigger date. Accordingly, a total distribution of approximately $6.8 million will be made to the Company's eligible employees under the Plan, of which 25% of the total distribution, or $1.7 million, was paid in February 2013 and the remaining 75%, or $5.1 million, will be deferred until August 2014 in accordance with the Plan.

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13. Derivative Instruments and Hedging Activities

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company's credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company's risk management policies and not subjecting the Company to material speculative risks. All of the Company's derivatives are used for risk management purposes and are not held for trading purposes.

As of December 31, 2012, the Company had the following outstanding commodity derivatives designated as hedging instruments:

Commodity and Derivative Type |  | Weighted-Average Contract Price |  | Volume |  | Contract Period
--- | --- | --- | --- | --- | --- | ---
Natural gas collars |  | $3.09 Floor / $4.12 Ceiling |  | per Mcf |  |  | 35.5 |  | Bcf |  | Jan. 2013 - Dec. 2013
Natural gas collars |  | $3.35 Floor / $4.01 Ceiling |  | per Mcf |  |  | 35.5 |  | Bcf |  | Jan. 2013 - Dec. 2013
Natural gas collars |  | $3.40 Floor / $4.12 Ceiling |  | per Mcf |  |  | 17.7 |  | Bcf |  | Jan. 2013 - Dec. 2013
Natural gas collars |  | $3.60 Floor / $4.17 Ceiling |  | per Mcf |  |  | 17.7 |  | Bcf |  | Jan. 2013 - Dec. 2013
Natural gas collars |  | $3.76 Floor / $4.16 Ceiling |  | per Mcf |  |  | 17.7 |  | Bcf |  | Jan. 2013 - Dec. 2013
Natural gas collars |  | $3.86 Floor / $4.34 Ceiling |  | per Mcf |  |  | 17.7 |  | Bcf |  | Jan. 2013 - Dec. 2013
Natural gas collars |  | $5.15 Floor / $6.20 Ceiling |  | per Mcf |  |  | 17.7 |  | Bcf |  | Jan. 2013 - Dec. 2013
Crude oil swaps |  | $101.90 |  | per Bbl |  |  | 1,095 |  | Mbbl |  | Jan. 2013 - Dec. 2013

The change in fair value of derivatives designated as hedges that is effective is recorded to Accumulated other comprehensive income in Stockholders' equity in the Consolidated Balance Sheet. The ineffective portion of the change in the fair value of derivatives designated as hedges, and the change in fair value of derivatives not designated as hedges, are recorded currently in earnings as a component of Natural gas revenue and Crude oil and condensate revenue in the Consolidated Statement of Operations.

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

Effect of Derivative Instruments on the Consolidated Balance Sheet

|  | Fair Values of Derivative Instruments |
--- | --- | --- | ---
|  | Asset Derivatives |  |  |  | Liability Derivatives |
|  |  |  | December 31, |  |  |  |  |  | December 31, |
|  | Balance Sheet Location |  | 2012 |  | 2011 |  |  |  | Balance Sheet Location |  | 2012 |  | 2011 |
(In thousands) |  |  |
Derivatives Designated as Hedging Instruments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts |  | Derivative instruments (current assets) |  | $ | 50,824 |  | $ | 177,389 |  |  |  | Derivative instruments (current assets) |  | $ | — |  | $ | — |
Commodity contracts |  | Accrued liabilities |  |  | — |  |  | — |  |  |  | Accrued liabilities |  |  | (192 | ) |  | (385 | )
Commodity contracts |  | Derivative instruments (non-current assets) |  |  | — |  |  | 21,249 |  |  |  | Derivative instruments (non-current assets) |  |  | — |  |  | — |
Commodity contracts |  | Other liabilities |  |  | — |  |  | — |  |  |  | Other liabilities |  |  | — |  |  | — |
|  |  |  |  | 50,824 |  |  | 198,638 |  |  |  |  |  |  | (192 | ) |  | (385 | )
Derivatives Not Designated as Hedging Instruments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity contracts |  | Derivative instruments (current assets) |  |  | — |  |  | — |  |  |  | Derivative instruments (current assets) |  |  | — |  |  | (3,126 | )
|  |  |  | $ | 50,824 |  | $ | 198,638 |  |  |  |  |  | $ | (192 | ) | $ | (3,511 | )

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At December 31, 2012 and 2011, unrealized gains of $50.6 million ($30.7 million, net of tax) and $198.3 million ($121.3 million, net of tax), respectively, were recorded in Accumulated other comprehensive income in the Consolidated Balance Sheet. Based upon estimates at December 31, 2012, the Company expects to reclassify $30.7 million in after-tax income associated with its commodity hedges from Accumulated other comprehensive income to the Consolidated Statement of Operations over the next 12 months.

Effect of Derivative Instruments on the Consolidated Statement of Operations

|  | Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion) |  |  |  | Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) |
--- | --- | --- | --- | --- | --- | --- | ---
|  | Year Ended December 31, |  | Location of Gain (Loss) Reclassified from Accumulated OCI into Income (In thousands) |  | Year Ended December 31, |
Derivatives Designated as Hedging Instruments (In thousands) |
| 2012 |  | 2011 |  | 2010 |  | 2012 |  | 2011 |  | 2010 |
Commodity Contracts |  | $ | 88,705 |  | $ | 267,667 |  | $ | 75,655 |  | Natural gas revenues |  | $ | 225,108 |  | $ | 84,937 |  | $ | 154,960 |
|  |  |  |  |  |  |  |  |  |  | Crude oil and condensate revenues |  |  | 11,218 |  |  | 1,403 |  |  | 18,030 |
|  |  |  |  |  |  |  |  |  |  |  |  | $ | 236,326 |  | $ | 86,340 |  | $ | 172,990 |

For the years ended December 31, 2012, 2011 and 2010, respectively, there was no ineffectiveness recorded in our Consolidated Statement of Operations related to our derivative instruments.

|  |  |  | Year Ended December 31, |
--- | --- | --- | --- | --- | ---
Derivatives Not Designated as Hedging Instruments (In thousands) |  | Location of Gain (Loss) Recognized in Income on Derivative |
| 2012 |  | 2011 |  | 2010 |
Commodity Contracts |  | Natural gas revenues |  | $ | (494 | ) | $ | (965 | ) | $ | (226 | )

Additional Disclosures about Derivative Instruments and Hedging Activities

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

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

14. Fair Value Measurements

The Company follows fair value measurement authoritative accounting guidance for measuring fair values of assets and liabilities in financial statements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company is able to classify fair value balances based on the observability of

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these inputs. The authoritative guidance for fair value measurements establishes three levels of the fair value hierarchy, defined as follows:

•
  Level 1: Unadjusted, quoted prices for identical assets or liabilities in active markets
•
  Level 2: Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability.
•
  Level 3: Significant, unobservable inputs for use when little or no market data exists, requiring a significant degree of judgment.

The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. Depending on the particular asset or liability, input availability can vary depending on factors such as product type, longevity of a product in the market and other particular transaction conditions. In some cases, certain inputs used to measure fair value may be categorized into different levels of the fair value hierarchy. For disclosure purposes under the accounting guidance, the lowest level that contains significant inputs used in valuation should be chosen.

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of oil and gas properties and other assets and asset retirement obligations, at fair value on a nonrecurring basis.

During the year ended December 31, 2010, the Company recorded impairment charges related to certain oil and gas properties and other assets. Refer to Note 2 for additional disclosures related to fair value associated with the impaired assets. As none of the Company's other non-financial assets and liabilities were impaired as of December 31, 2012, 2011 and 2010 and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures were not provided.

The estimated fair value of the Company's asset retirement obligation at inception is determined by utilizing the income approach by applying a credit-adjusted risk-free rate, which takes into account the Company's credit risk, the time value of money, and the current economic state, to the undiscounted expected abandonment cash flows. Given the unobservable nature of the inputs, the measurement of the asset retirement obligation is deemed to use Level 3 inputs.

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Financial Assets and Liabilities

Our financial assets and liabilities are measured at fair value on a recurring basis. The following fair value hierarchy table presents information about the Company's financial assets and liabilities measured at fair value on a recurring basis:

(In thousands) |  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  | Balance as of December 31, 2012 |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Assets |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 10,608 |  | $ | — |  | $ | — |  | $ | 10,608 |
Derivative contracts |  |  | — |  |  | 9,473 |  |  | 41,351 |  |  | 50,824 |
Total assets |  | $ | 10,608 |  | $ | 9,473 |  | $ | 41,351 |  | $ | 61,432 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 23,893 |  | $ | — |  | $ | — |  | $ | 23,893 |
Derivative contracts |  |  | — |  |  | — |  |  | 192 |  |  | 192 |
Total liabilities |  | $ | 23,893 |  | $ | — |  | $ | 192 |  | $ | 24,085 |

(In thousands) |  | Quoted Prices in Active Markets for Identical Assets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  | Balance as of December 31, 2011 |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Assets |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 10,838 |  | $ | — |  | $ | — |  | $ | 10,838 |
Derivative contracts |  |  | — |  |  | — |  |  | 195,512 |  |  | 195,512 |
Total assets |  | $ | 10,838 |  | $ | — |  | $ | 195,512 |  | $ | 206,350 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred compensation plan |  | $ | 20,187 |  | $ | — |  | $ | — |  | $ | 20,187 |
Derivative contracts |  |  | — |  |  | — |  |  | 385 |  |  | 385 |
Total liabilities |  | $ | 20,187 |  | $ | — |  | $ | 385 |  | $ | 20,572 |

The Company's investments associated with its deferred compensation plan consist of mutual funds and deferred shares of the Company's common stock that are publicly traded and for which market prices are readily available.

The derivative contracts were measured based on quotes from the Company's counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The determination of the fair values presented above also incorporate a credit adjustment for non-performance risk. The Company measured the nonperformance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions in which it has derivative transactions while nonperformance risk of the Company is evaluated using a market credit spread provided by the Company's bank.

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The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties' valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Balance at beginning of period |  | $ | 195,127 |  | $ | 14,746 |  | $ | 112,307 |
Total gains or (losses) (realized or unrealized): |  |  |  |  |  |  |  |  |  |
Included in earnings(1) |  |  | 224,614 |  |  | 85,375 |  |  | 172,764 |
Included in other comprehensive income |  |  | (157,478 | ) |  | 181,346 |  |  | (97,335 | )
Settlements |  |  | (221,489 | ) |  | (86,340 | ) |  | (172,990 | )
Transfers in and/or out of level 3 |  |  | 385 |  |  | — |  |  | — |
Balance at end of period |  | $ | 41,159 |  | $ | 195,127 |  | $ | 14,746 |

(1)
  A loss of $0.5 million, $1.0 million and $0.2 million for the years ended December 31, 2012, 2011 and 2010, respectively, was unrealized and included in Natural gas revenues in the Consolidated Statement of Operations.

There were no transfers between Level 1 and Level 2 measurements for the years ended December 31, 2012, 2011 and 2010.

Fair Value of Other Financial Instruments

The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short-term maturities of these instruments. Based on the inputs used to fair value these financial instruments, cash and cash equivalents are deemed to use Level 1 inputs and the remaining financial instruments are deemed to use Level 2.

The fair value of long-term debt is the estimated amount the Company would have to pay a third party to assume the debt, including a credit spread for the difference between the issue rate and the period end market rate. The credit spread is the Company's default or repayment risk. The credit spread (premium or discount) is determined by comparing the Company's fixed-rate notes and credit facility to new issuances (secured and unsecured) and secondary trades of similar size and credit statistics for both public and private debt. The fair value of all of the fixed-rate notes and credit facility is based on interest rates currently available to the Company. Given the unobservable nature of the inputs, the fair value of long-term debt is deemed to use Level 3 inputs.

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14. Fair Value Measurements (Continued)

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

|  | December 31, 2012 |  | December 31, 2011 |
--- | --- | --- | --- | --- | ---
(In thousands) |  | Carrying Amount |  | Estimated Fair Value |  | Carrying Amount |  | Estimated Fair Value |
Long-term debt |  | $ | 1,087,000 |  | $ | 1,213,474 |  | $ | 950,000 |  | $ | 1,082,531 |
Current maturities |  |  | (75,000 | ) |  | (77,175 | ) |  | — |  |  | — |
Long-term debt, excluding current maturities |  | $ | 1,012,000 |  | $ | 1,136,299 |  | $ | 950,000 |  | $ | 1,082,531 |

15. Earnings per Common Share

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

The following is a calculation of basic and diluted weighted-average shares outstanding:

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Weighted-average shares—basic |  |  | 209,538 |  |  | 208,498 |  |  | 207,823 |
Dilution effect of stock options, stock appreciation rights and stock awards at end of period |  |  | 1,455 |  |  | 2,263 |  |  | 2,567 |
Weighted-average shares—diluted |  |  | 210,993 |  |  | 210,761 |  |  | 210,390 |
Weighted-average stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect |  |  | 43 |  |  | 2 |  |  | 567 |

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16. Accumulated Other Comprehensive Income / (Loss)

Changes in the components of accumulated other comprehensive income / (loss), net of taxes, were as follows:

(In thousands) |  | Net Gains / (Losses) on Cash Flow Hedges |  | Defined Benefit Pension and Postretirement Plans |  | Foreign Currency Translation Adjustment |  | Total |
--- | --- | --- | --- | --- | --- | --- | --- | --- | ---
Balance at December 31, 2009 |  | $ | 71,872 |  | $ | (29,349 | ) | $ | (87 | ) | $ | 42,436 |
Net change in unrealized gain on cash flow hedges, net of taxes of $35,957 |  |  | (61,378 | ) |  | — |  |  | — |  |  | (61,378 | )
Net change in defined benefit pension and postretirement plans, net of taxes of ($9,088) |  |  | — |  |  | 15,227 |  |  | — |  |  | 15,227 |
Change in foreign currency translation adjustment, net of taxes of ($20) |  |  | — |  |  | — |  |  | 32 |  |  | 32 |
Balance at December 31, 2010 |  | $ | 10,494 |  | $ | (14,122 | ) | $ | (55 | ) | $ | (3,683 | )
Net change in unrealized gain on cash flow hedges, net of taxes of ($70,463) |  |  | 110,864 |  |  | — |  |  | — |  |  | 110,864 |
Net change in defined benefit pension and postretirement plans, net of taxes of $2,225 |  |  | — |  |  | (2,689 | ) |  | — |  |  | (2,689 | )
Change in foreign currency translation adjustment, net of taxes of $(34) |  |  | — |  |  | — |  |  | 55 |  |  | 55 |
Balance at December 31, 2011 |  | $ | 121,358 |  | $ | (16,811 | ) |  | — |  | $ | 104,547 |
Net change in unrealized gain on cash flow hedges, net of taxes of $56,980 |  |  | (90,641 | ) |  | — |  |  | — |  |  | (90,641 | )
Net change in defined benefit pension and postretirement plans, net of taxes of $(6,226) |  |  | — |  |  | 9,974 |  |  | — |  |  | 9,974 |
Balance at December 31, 2012 |  | $ | 30,717 |  | $ | (6,837 | ) |  | — |  | $ | 23,880 |

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CABOT OIL & GAS CORPORATION
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserves

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

Estimates of total proved reserves at December 31, 2012, 2011 and 2010 were based on studies performed by the Company's petroleum engineering staff. The estimates were computed using the 12-month average crude oil and natural gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year. The estimates were audited by Miller and Lents, Ltd., who indicated that based on their investigation and subject to the limitations described in their audit letter, they believe the results of those estimates and projections were reasonable in the aggregate.

No major discovery or other favorable or unfavorable event after December 31, 2012, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

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The following tables illustrate the Company's net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated, as estimated by the Company's engineering staff. All reserves are located within the continental United States in 2012, 2011 and 2010.

|  | Natural Gas |  | Crude Oil & Liquids |  | Total |
--- | --- | --- | --- | --- | --- | --- | ---
|  | (Bcf) |  | (Mbbl) |  | (Bcfe)(1) |
December 31, 2009 |  |  | 2,013 |  |  | 7,783 |  |  | 2,060 |
Revision of Prior Estimates(2) |  |  | 139 |  |  | (379 | ) |  | 137 |
Extensions, Discoveries and Other Additions(3) |  |  | 633 |  |  | 2,944 |  |  | 650 |
Production |  |  | (126 | ) |  | (858 | ) |  | (131 | )
Purchases of Reserves in Place |  |  | 1 |  |  | 4 |  |  | 1 |
Sales of Reserves in Place |  |  | (16 | ) |  | (3 | ) |  | (16 | )
December 31, 2010 |  |  | 2,644 |  |  | 9,491 |  |  | 2,701 |
Revision of Prior Estimates(4) |  |  | 22 |  |  | (80 | ) |  | 22 |
Extensions, Discoveries and Other Additions(3) |  |  | 629 |  |  | 13,583 |  |  | 710 |
Production |  |  | (179 | ) |  | (1,444 | ) |  | (188 | )
Sales of Reserves in Place(5) |  |  | (206 | ) |  | (1,080 | ) |  | (212 | )
December 31, 2011 |  |  | 2,910 |  |  | 20,470 |  |  | 3,033 |
Revision of Prior Estimates(6) |  |  | 207 |  |  | (3,101 | ) |  | 189 |
Extensions, Discoveries and Other Additions(3) |  |  | 869 |  |  | 9,628 |  |  | 926 |
Production |  |  | (253 | ) |  | (2,407 | ) |  | (268 | )
Sales of Reserves in Place |  |  | (37 | ) |  | (216 | ) |  | (38 | )
December 31, 2012 |  |  | 3,696 |  |  | 24,374 |  |  | 3,842 |
Proved Developed Reserves |  |  |  |  |  |  |  |  |  |
December 31, 2009 |  |  | 1,288 |  |  | 6,082 |  |  | 1,325 |
December 31, 2010 |  |  | 1,681 |  |  | 7,129 |  |  | 1,724 |
December 31, 2011 |  |  | 1,734 |  |  | 10,922 |  |  | 1,800 |
December 31, 2012 |  |  | 2,216 |  |  | 12,828 |  |  | 2,293 |
Proved Undeveloped Reserves |  |  |  |  |  |  |  |  |  |
December 31, 2009 |  |  | 725 |  |  | 1,701 |  |  | 735 |
December 31, 2010 |  |  | 963 |  |  | 2,362 |  |  | 977 |
December 31, 2011 |  |  | 1,176 |  |  | 9,548 |  |  | 1,233 |
December 31, 2012 |  |  | 1,480 |  |  | 11,546 |  |  | 1,549 |

(1)
  Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.
(2)
  The net upward revision of 136.7 Bcfe was primarily due to (i) an upward performance revision of 284.4 Bcfe, primarily in the Dimock field in northeast Pennsylvania, and (ii) an upward revision of 35.0 Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of 182.7 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.
(3)
  Extensions, discoveries and other additions were primarily related to drilling activity in the Dimock field located in northeast Pennsylvania. The Company added 860.6 Bcfe, 616.1 Bcfe and 536.6 Bcfe of proved reserves in this field in 2012, 2011 and 2010, respectively.
(4)
  The net upward revision of 21.6 Bcfe was primarily due to an upward performance revision of 214.9 Bcfe, primarily in the Dimock field in northeast Pennsylvania, partially offset by (i) a downward

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revision of 189.8 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan and (ii) a downward revision of 3.6 Bcfe associated with reduced reserve commodity pricing.

(5)
  Sales of reserves in place were primarily related to the divestiture of certain oil and gas properties in the Rockies in October 2011 which represented 170.3 Bcfe.
(6)
  The net upward revision of 188.6 Bcfe was primarily due to an upward performance revision of 369.6 Bcfe, primarily in the Dimock field in northeast Pennsylvania, partially offset by (i) a downward revision of 114.5 Bcfe associated with reduced reserve commodity pricing and (ii) a downward revision of 66.5 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.

Capitalized Costs Relating to Oil and Gas Producing Activities

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

|  | December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Aggregate capitalized costs relating to oil and gas producing activities |  | $ | 6,507,137 |  | $ | 5,794,724 |  | $ | 5,598,842 |
Aggregate accumulated depreciation, depletion and amortization |  |  | 2,200,061 |  |  | 1,864,729 |  |  | 1,840,091 |
Net capitalized costs |  | $ | 4,307,076 |  | $ | 3,929,995 |  | $ | 3,758,751 |

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

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

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Property acquisition costs, proved |  | $ | — |  | $ | — |  | $ | 801 |
Property acquisition costs, unproved |  |  | 88,880 |  |  | 71,134 |  |  | 130,675 |
Exploration costs |  |  | 59,198 |  |  | 53,484 |  |  | 66,368 |
Development costs |  |  | 821,806 |  |  | 763,635 |  |  | 630,511 |
Total costs |  | $ | 969,884 |  | $ | 888,253 |  | $ | 828,355 |

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

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

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

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

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•
  Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.
•
  Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.
•
  Future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows for 2012, 2011 and 2010 were estimated by using the 12-month average crude oil and natural gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year.

The average prices (adjusted for basis and quality differentials) related to proved reserves at December 31, 2012, 2011 and 2010 for natural gas ($ per Mcf) were $2.83, $4.27 and $4.33, respectively, and for crude oil and liquids ($ per Bbl) were $96.43, $94.00 and $74.25, respectively. Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations. The applicable accounting standards require the use of a 10% discount rate.

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

Standardized Measure is as follows:

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Future cash inflows |  | $ | 12,826,877 |  | $ | 14,303,990 |  | $ | 12,147,617 |
Future production costs |  |  | (4,300,025 | ) |  | (3,435,947 | ) |  | (2,377,402 | )
Future development costs |  |  | (1,614,878 | ) |  | (1,617,548 | ) |  | (1,670,796 | )
Future income tax expenses |  |  | (1,873,185 | ) |  | (2,880,182 | ) |  | (2,357,935 | )
Future net cash flows |  |  | 5,038,789 |  |  | 6,370,313 |  |  | 5,741,484 |
10% annual discount for estimated timing of cash flows |  |  | (2,302,934 | ) |  | (3,211,587 | ) |  | (3,006,975 | )
Standardized measure of discounted future net cash flows |  | $ | 2,735,855 |  | $ | 3,158,726 |  | $ | 2,734,509 |

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

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

|  | Year Ended December 31, |
--- | --- | --- | ---
(In thousands) |  | 2012 |  | 2011 |  | 2010 |
Beginning of year |  | $ | 3,158,726 |  | $ | 2,734,509 |  | $ | 1,631,735 |
Discoveries and extensions, net of related future costs |  |  | 911,044 |  |  | 1,026,961 |  |  | 780,917 |
Net changes in prices and production costs |  |  | (1,682,131 | ) |  | 219,478 |  |  | 991,942 |
Accretion of discount |  |  | 400,091 |  |  | 325,634 |  |  | 164,189 |
Revisions of previous quantity estimates |  |  | 139,540 |  |  | 28,443 |  |  | 164,851 |
Timing and other |  |  | (243,688 | ) |  | (190,427 | ) |  | (105,331 | )
Development costs incurred |  |  | 282,476 |  |  | 190,295 |  |  | 115,560 |
Sales and transfers, net of production costs |  |  | (636,633 | ) |  | (648,261 | ) |  | (481,556 | )
Net purchases / (sales) of reserves in place |  |  | (37,412 | ) |  | (207,557 | ) |  | (16,124 | )
Net change in income taxes |  |  | 443,842 |  |  | (320,349 | ) |  | (511,674 | )
End of year |  | $ | 2,735,855 |  | $ | 3,158,726 |  | $ | 2,734,509 |

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CABOT OIL & GAS CORPORATION

SELECTED DATA (UNAUDITED)

QUARTERLY FINANCIAL INFORMATION

(In thousands, except per share amounts) |  | First |  | Second |  | Third |  | Fourth |  | Total |
--- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | ---
2012 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $ | 272,136 |  | $ | 265,657 |  | $ | 296,874 |  | $ | 369,879 |  | $ | 1,204,546 |
Operating income(1) |  |  | 46,661 |  |  | 78,079 |  |  | 75,775 |  |  | 105,618 |  |  | 306,133 |
Net income(1) |  |  | 18,318 |  |  | 35,937 |  |  | 36,608 |  |  | 40,867 |  |  | 131,730 |
Basic earnings per share(2) |  |  | 0.09 |  |  | 0.17 |  |  | 0.17 |  |  | 0.19 |  |  | 0.63 |
Diluted earnings per share(2) |  |  | 0.09 |  |  | 0.17 |  |  | 0.17 |  |  | 0.19 |  |  | 0.62 |
2011 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues |  | $ | 209,026 |  | $ | 240,696 |  | $ | 262,117 |  | $ | 268,025 |  | $ | 979,864 |
Operating income(3) |  |  | 36,390 |  |  | 106,618 |  |  | 65,233 |  |  | 98,609 |  |  | 306,850 |
Net income(3) |  |  | 12,886 |  |  | 54,677 |  |  | 28,482 |  |  | 26,363 |  |  | 122,408 |
Basic earnings per share(2) |  |  | 0.06 |  |  | 0.27 |  |  | 0.14 |  |  | 0.13 |  |  | 0.59 |
Diluted earnings per share(2) |  |  | 0.06 |  |  | 0.26 |  |  | 0.14 |  |  | 0.13 |  |  | 0.58 |

(1)
  Operating income and Net income include a $67.0 million gain on the disposition of certain of Pearsall shale undeveloped acreage in south Texas in the second quarter, partially offset by an $18.2 million loss on sale of certain of our south Texas proved oil and gas properties in the fourth quarter.
(2)
  All Earnings per Share figures have been retroactively adjusted for the 2-for-1 split of the Company's common stock effective January 25, 2012.
(3)
  Operating income and Net income include a $34.2 million gain on the disposition of certain Haynesville and Bossier Shale oil and gas properties in east Texas in the second quarter and an aggregate gain of $29.2 million from the sale of various other properties primarily in the fourth quarter.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

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

As of December 31, 2012, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the "Exchange Act"). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission's rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

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

Management's Report on Internal Control over Financial Reporting

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

Cabot Oil & Gas Corporation's management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2012. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework. Based on this assessment management has concluded that, as of December 31, 2012, the Company's internal control over financial reporting is effective at a reasonable assurance level based on those criteria.

The effectiveness of Cabot Oil & Gas Corporation's internal control over financial reporting as of December 31, 2012, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2013 annual stockholders' meeting. In addition, the information set forth under the caption "Business—Other Business Matters—Corporate Governance Matters" in Item 1 regarding our Code of Business Conduct is incorporated by reference in response to this Item.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2013 annual stockholders' meeting.

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

The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2013 annual stockholders' meeting.

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

The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2013 annual stockholders' meeting.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is incorporated by reference to the Company's definitive Proxy Statement in connection with the 2013 annual stockholders' meeting.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

A. INDEX

1. Consolidated Financial Statements

See Index on page 57.

2. Financial Statement Schedules

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

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3. Exhibits

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

Exhibit Number |  | Description
--- | --- | ---
| 3.1 |  | Restated Certificate of Incorporation of the Company (Form 8-K for January 21, 2010).
| 3.2 |  | Certificate of Amendment of Restated Certificate of Incorporation, dated as of May 1, 2012 (Form 10-Q for the quarter ended June 30, 2012).
| 3.3 |  | Amended and Restated Bylaws, effective as of February 17, 2012 (Form 10-Q for the quarter ended June 30, 2012).
| 4.1 |  | Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553).
| 4.2 |  | Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K for August 30, 2001).
|  |  | (a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
|  |  | (b) Amendment No. 2 to Note Purchase Agreement, dated as of September 28, 2010 (Form 10-Q for the quarter ended September 30, 2010).
| 4.3 |  | Note Purchase Agreement dated as of July 16, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 8-K for July 16, 2008).
|  |  | (a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
| 4.4 |  | Note Purchase Agreement dated as of December 1, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 10-K for 2008).
|  |  | (a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
| 4.5 |  | Note Purchase Agreement dated as of December 30, 2010 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 10-K for 2010).
| 4.6 |  | Credit Agreement, dated as of September 22, 2010, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities LLC, as Syndication Agent, Bank of Montreal, as Documentation Agent, and the Lenders party thereto (Form 10-Q for the quarter ended September 30, 2010).
| 4.7 |  | First Amendment to Amended and Restated Credit Agreement, dated as of May 4, 2012, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities as Syndication Agent, Bank of Montreal as Documentation Agent, and the Lenders party thereto (Form 10-Q for the quarter ended June 30, 2012).
| 4.8 |  | Second Amendment to Amended and Restated Credit Agreement, dated as of July 18, 2012, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities and Bank of Montreal as Co-Syndication Agents, BNP Paribas and Wells Fargo as Co-Documentation Agents, and the Lenders party thereto (Form 10-Q for the quarter ended September 30, 2012).

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Exhibit Number |  | Description
--- | --- | ---
| *10.1 |  | Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 2008).
|  |  | (a) Form of Change in Control Agreement between the Company and Certain Officers (Confirmation that Certain Benefits no Longer Apply) (Form 10-K for 2010).
| *10.2 |  | Form of Indemnity Agreement between the Company and Certain Officers.
| *10.3 |  | Deferred Compensation Plan of the Company, as Amended and Restated, Effective January 1, 2011 (Form 10-Q for the quarter ended June 30, 2011).
| *10.4 |  | Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001).
|  |  | (a) Amendment to Employment Agreement between the Company and Dan O. Dinges, effective December 31, 2008 (Form 10-K for 2008).
| *10.5 |  | 2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004).
|  |  | (a) First Amendment to the 2004 Incentive Plan effective February 23, 2007 (Form 10-Q for the quarter ended March 31, 2007).
|  |  | (b) Second Amendment to the 2004 Incentive Plan Amendment, effective as of December 31, 2008 (Form 10-K for 2008).
| *10.6 |  | 2012 Form of Non-Employee Director Restricted Stock Unit Award Agreement.
| *10.7 |  | Forms of Award Agreements for Executive Officers under 2004 Incentive Plan.
|  |  | (a) 2012 Form of Restricted Stock Award Agreement.
|  |  | (b) 2012 Form of Stock Appreciation Rights Award Agreement.
|  |  | (c) 2012 Form of Performance Share Award Agreement (Officers).
|  |  | (d) 2012 Form of Hybrid Performance Share Award Agreement.
|  |  | (e) 2012 Form of Performance Share Award Agreement (Employees).
| 10.8 |  | Cabot Oil & Gas Corporation Mineral, Royalty and Overriding Royalty Interest Plan (Registration Statement No. 333-135365).
|  |  | (a) Form of Conveyance of Mineral and/or Royalty Interest (Registration Statement No. 333-135365).
|  |  | (b) Form of Conveyance of Overriding Royalty Interest (Registration Statement No. 333-135365).
| *10.9 |  | Savings Investment Plan of the Company, as amended and restated effective January 1, 2009 (Form 10-K for 2009).
|  |  | (a) First Amendment to the Savings Investment Plan of the Company effective October 1, 2010 (Form 10-K for 2010).
| *10.10 |  | Nonemployee Director Deferred Compensation Plan effective December 21, 2012.
| 21.1 |  | Subsidiaries of Cabot Oil & Gas Corporation.
| 23.1 |  | Consent of PricewaterhouseCoopers LLP.
| 23.2 |  | Consent of Miller and Lents, Ltd.

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Exhibit Number |  | Description
--- | --- | ---
| 31.1 |  | 302 Certification—Chairman, President and Chief Executive Officer.
| 31.2 |  | 302 Certification—Vice President and Chief Financial Officer.
| 32.1 |  | 906 Certification.
| 99.1 |  | Miller and Lents, Ltd. Audit Letter.
| 101.INS |  | XBRL Instance Document.
| 101.SCH |  | XBRL Taxonomy Extension Schema Document.
| 101.CAL |  | XBRL Taxonomy Extension Calculation Linkbase Document.
| 101.LAB |  | XBRL Taxonomy Extension Label Linkbase Document.
| 101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document.
| 101.DEF |  | XBRL Taxonomy Extension Definition Linkbase Document.

*
  Compensatory plan, contract or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 and 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 28th of February 2013.

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

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

Signature |  | Title |  | Date
--- | --- | --- | --- | ---
/s/ DAN O. DINGES Dan O. Dinges |  | Chairman, President and Chief Executive Officer (Principal Executive Officer) |  | February 28, 2013
/s/ SCOTT C. SCHROEDER Scott C. Schroeder |  | Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) |  | February 28, 2013
/s/ TODD M. ROEMER Todd M. Roemer |  | Controller (Principal Accounting Officer) |  | February 28, 2013
/s/ RHYS J. BEST Rhys J. Best |  | Director |  | February 28, 2013
/s/ JAMES R. GIBBS James R. Gibbs |  | Director |  | February 28, 2013
/s/ ROBERT L. KEISER Robert L. Keiser |  | Director |  | February 28, 2013
/s/ ROBERT KELLEY Robert Kelley |  | Director |  | February 28, 2013

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Signature |  | Title |  | Date
--- | --- | --- | --- | ---
/s/ P. DEXTER PEACOCK P. Dexter Peacock |  | Director |  | February 28, 2013
/s/ W. MATT RALLS W. Matt Ralls |  | Director |  | February 28, 2013

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