CABOT OIL & GAS CORP (Form: 10-K, Received: 02/28/2013 16:23:05)

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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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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

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.



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:

•: 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;
•: the level of consumer product demand;
•: weather conditions;
•: political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;
•: 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;
•: the price level of foreign imports;
•: actions of governmental authorities;
•: 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;
•: inventory storage levels;
•: the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;
•: the price, availability and acceptance of alternative fuels;

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•: technological advances affecting energy consumption;
•: speculation by investors in oil and gas;
•: variations between product prices at sales points and applicable index prices; and
•: 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:

•: unexpected drilling conditions, pressure or irregularities in formations;
•: equipment failures or accidents;
•: adverse weather conditions;
•: decreases in natural gas and oil prices;
•: surface access restrictions;
•: loss of title or other title related issues;
•: compliance with, or changes in, governmental requirements and regulation; and
•: 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:

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

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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:

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

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

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

Our business involves a variety of operating risks, including:

•: well site blowouts, cratering and explosions;
•: equipment failures;

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

Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, 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:

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

We will continue to evaluate the benefit of 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		Position

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
					Variance					Increase (Decrease) (In thousands)
	2012		2011		Amount			Percent		Increase (Decrease) (In thousands)
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,

	Year Ended December 31,				Variance					Price and Volume Variances (In thousands)
	2012		2011		Amount			Percent		Price and Volume Variances (In thousands)
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
					Variance					Increase (Decrease) (In thousands)
	2011		2010		Amount			Percent		Increase (Decrease) (In thousands)
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,

	Year Ended December 31,				Variance					Price and Volume Variances (In thousands)
	2011		2010		Amount			Percent		Price and Volume Variances (In thousands)
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

	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		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.

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 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)		Stock Par			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.

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1. Summary of Significant Accounting Policies (Continued)

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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1. Summary of Significant Accounting Policies (Continued)

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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1. Summary of Significant Accounting Policies (Continued)

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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1. Summary of Significant Accounting Policies (Continued)

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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1. Summary of Significant Accounting Policies (Continued)

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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2. Properties and Equipment, Net (Continued)

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		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		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%	³ 25% <50%	³ 50% <75%	³ 75% <90%	³ 90%
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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6. Employee Benefit Plans (Continued)

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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7. Income Taxes (Continued)

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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7. Income Taxes (Continued)

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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8. Commitments and Contingencies (Continued)

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			Weighted- Average Grant Date Fair Value per Share			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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12. Stock-Based Compensation (Continued)

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			Weighted- Average Grant Date Fair Value per Unit			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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12. Stock-Based Compensation (Continued)

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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12. Stock-Based Compensation (Continued)

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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12. Stock-Based Compensation (Continued)

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

Performance Share Awards			Weighted- Average Grant Date Fair Value per Share ⁽¹⁾			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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12. Stock-Based Compensation (Continued)

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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12. Stock-Based Compensation (Continued)

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				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,
		December 31,					December 31,
	Balance Sheet Location	2012		2011		Balance Sheet Location	2012			2011
(In thousands)	Balance Sheet Location	2012		2011		Balance Sheet Location	2012			2011
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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13. Derivative Instruments and Hedging Activities (Continued)

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)	Year Ended December 31,							Year Ended December 31,
	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	Year Ended December 31,
	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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14. Fair Value Measurements (Continued)

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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14. Fair Value Measurements (Continued)

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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Exhibit 10.2

CABOT OIL & GAS CORPORATION

INDEMNIFICATION AGREEMENT

This Indemnification Agreement is made and entered into this day of , 201 (“Agreement”), by and between CABOT OIL & GAS CORPORATION, a Delaware corporation (“Company”), and (“Indemnitee”).

WHEREAS, highly competent persons are becoming more reluctant to continue to serve publicly held corporations as directors or in other capacities unless they are provided with adequate protection through insurance or adequate indemnification against inordinate risks of claims and actions against them arising out of their service to and activities on behalf of the corporation;

WHEREAS, it is reasonable, prudent and necessary for the Company contractually to obligate itself to indemnify such persons as permitted by applicable law so that they will serve or continue to serve the Company free from undue concern that they will not be so indemnified; and

WHEREAS, Indemnitee is willing to serve, continue to serve and to take on additional service for or on behalf of the Company on the condition that he be so indemnified;

NOW THEREFORE, in consideration of the premises and the covenants contained herein, the Company and Indemnitee do hereby covenant and agree as follows:

Section 1. Services by Indemnitee. Indemnitee agrees to serve, or to continue to serve, at the request of the Company as a director, officer or employee. Indemnitee may at any time and for any reason resign from such position (subject to any other contractual obligation or any obligation imposed by operation of law). The Company shall have no obligation under this Agreement to continue Indemnitee in any such position.

Section 2. Indemnification - General. The Company shall indemnify, and advance Expenses (as defined in Section 17 hereof) to, Indemnitee as provided in this Agreement and to the fullest extent permitted by applicable law in effect on the date hereof and to such greater extent as applicable law may hereafter from time to time permit. The rights of Indemnitee provided under the preceding sentence shall include, but shall not be limited to, the rights set forth in the other Sections of this Agreement.

Section 3. Proceedings Other Than Proceedings by or in the Right of the Company. Indemnitee shall be entitled to the rights of indemnification provided in this Section 3 if, by reason of his Corporate Status (as defined in Section 17 hereof), he is, or is threatened to be made, a party to any threatened, pending, or completed Proceeding (as defined in Section 17 hereof), other than a Proceeding by or in the right of the Company. Pursuant to this Section 3, Indemnitee shall be indemnified against Expenses, judgments, penalties, fines and amounts paid in settlement actually and reasonably incurred by him or on his behalf in connection with such Proceeding or any claim, issue or matter therein, if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Company and, with respect to any criminal Proceeding, had no reasonable cause to believe his conduct was unlawful. If Indemnitee is entitled to

indemnification pursuant to this Section 3 as to some claims, issues or matters in such Proceeding but not others, then the Company reserves the right to reasonably prorate in good faith its indemnification obligations arising under this Agreement.

Section 4. Proceedings by or in the Right of the Company. Indemnitee shall be entitled to the rights of indemnification provided in this Section 4 if, by reason of his Corporate Status, he is, or is threatened to be made, a party to any threatened, pending or completed Proceeding brought by or in the right of the Company to procure a judgment in its favor. Pursuant to this Section 4, Indemnitee shall be indemnified against Expenses actually and reasonably incurred by him or on his behalf in connection with such Proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Company. Notwithstanding the foregoing, no indemnification against such Expenses shall be made in respect of any claim, issue or matter in such Proceeding as to which Indemnitee shall have been adjudged to be liable to the Company if applicable law prohibits such indemnification; provided, however, that if applicable law so permits, indemnification against Expenses shall nevertheless be made by the Company in such event if and only to the extent that the Court of Chancery of the State of Delaware, or the court in which such Proceeding shall have been brought or is pending, shall determine.

Section 5. Indemnification for Expenses of a Party Who is Wholly or Partly Successful. Notwithstanding any other provision of this Agreement, to the extent that Indemnitee is, by reason of his Corporate Status, a party to and is successful, on the merits or otherwise, in any Proceeding, he shall be indemnified against all Expenses actually and reasonably incurred by him or on his behalf in connection therewith. If Indemnitee is not wholly successful in such Proceeding but is successful, on the merits or otherwise, as to one or more but less than all claims, issues or matters in such Proceeding, the Company shall indemnify Indemnitee against all Expenses actually and reasonably incurred by him or on his behalf in connection with each successfully resolved claim, issue or matter, with Expenses with respect to such Proceeding being reasonably prorated by the Company in good faith. For purposes of this Agreement and without limitation, if any claim, issue or matter in such a Proceeding is disposed of, on the merits or otherwise (including a disposition without prejudice), without (i) the disposition being adverse to Indemnitee, (ii) an adjudication that Indemnitee was liable to the Company, (iii) a plea of guilty or nolo contendere by Indemnitee, (iv) an adjudication that Indemnitee did not act in good faith and in a manner Indemnitee reasonably believed to be in or not opposed to the best interests of the Company, and (v) with respect to any criminal proceeding, an adjudication that Indemnitee had reasonable cause to believe Indemnitee’s conduct was unlawful, Indemnitee shall be considered for the purposes hereof to have been wholly successful with respect thereto.

Section 6. Indemnification for Expenses of a Witness. Notwithstanding any other provision of this Agreement, to the extent that Indemnitee is, by reason of his Corporate Status, a witness or otherwise participates in any Proceeding at a time when he is not named as a defendant or respondent in the Proceeding, he shall be indemnified against all Expenses actually and reasonably incurred by him or on his behalf in connection therewith.

Section 7. Advancement of Expenses. The Company shall advance all reasonable Expenses incurred by or on behalf of Indemnitee in connection with any Proceeding by reason of the Corporate Status within 20 days after the receipt by the Company of a statement or statements from Indemnitee requesting such advance or advances from time to time, whether prior to or after final

disposition of such Proceeding. Such statement or statements shall reasonably evidence the Expenses incurred by Indemnitee and shall include or be preceded or accompanied by an undertaking by or on behalf of Indemnitee to repay any Expenses advanced if it shall ultimately be determined that Indemnitee is not entitled to be indemnified against such Expenses.

Section 8. Procedure for Determination of Entitlement to Indemnification.

(a) To obtain indemnification under this Agreement, Indemnitee shall submit to the Company a written request, including therein or therewith such documentation and information as is reasonably available to Indemnitee and is reasonably necessary to determine whether and to what extent Indemnitee is entitled to indemnification. The Secretary of the Company shall, promptly upon receipt of such a request for indemnification, advise the Board of Directors in writing that Indemnitee has requested indemnification.

(b) Upon written request by Indemnitee for indemnification pursuant to the first sentence of Section 8(a) hereof, a determination, if required by applicable law, with respect to Indemnitee’s entitlement thereto shall be made in the specific case: (i) if a Change of Control (as hereinafter defined) shall have occurred, by Independent Counsel (as hereinafter defined) (unless Indemnitee shall request that such determination be made by the Board of Directors or the stockholders, in which case by the person or persons or in the manner provided for in clauses (ii) of this Section 8(b)) in a written opinion to the Board of Directors, a copy of which shall be delivered to Indemnitee; or (ii) if a Change of Control shall not have occurred, (A) by the Board of Directors by a majority vote of the Disinterested Directors (as hereinafter defined), even though less than a quorum or (B) if there are no Disinterested Directors or if the Disinterested Directors so direct, by Independent Counsel in a written opinion to the Board of Directors, a copy of which shall be delivered to Indemnitee or (C) if so directed by the Disinterested Directors, or if there are no Disinterested Directors, the Board of Directors, by the stockholders of the Company; and, if it is so determined that Indemnitee is entitled to indemnification, payment to Indemnitee shall be made within 10 days after such determination. Indemnitee shall cooperate with the person, persons or entity making such determination with respect to Indemnitee’s entitlement to indemnification, including providing to such person, persons or entity upon reasonable advance request any documentation or information which is not privileged or otherwise protected from disclosure and which is reasonably available to Indemnitee and reasonably necessary to such determination. Any costs or expenses (including attorneys’ fees and disbursements) incurred by Indemnitee in so cooperating with the person, persons or entity making such determination shall be borne by the Company (irrespective of the determination as to Indemnitee’s entitlement to indemnification), and the Company hereby indemnifies and agrees to hold Indemnitee harmless therefrom.

(c) In the event the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 8(b) hereof, the Independent Counsel shall be selected as provided in this Section 8(c). If a Change of Control shall not have occurred, the Independent Counsel shall be selected by the Board of Directors, and the Company shall give written notice to Indemnitee advising him of the identity of the Independent Counsel so selected. If a Change of Control shall have occurred, the Independent Counsel shall be selected by Indemnitee (unless Indemnitee shall request that such selection be made by the Board of Directors, in which event the preceding sentence shall apply), and Indemnitee shall give written notice to the Company advising it of the identity of the Independent Counsel so selected. In either event, Indemnitee or the

Company, as the case may be, may, within seven days after such written notice of selection shall have been given, deliver to the Company or to Indemnitee, as the case may be, a written objection to such selection. Such objection may be asserted only on the ground that the Independent Counsel so selected does not meet the requirements of “Independent Counsel” as defined in Section 17 of this Agreement, and the objection shall set forth with particularity the factual basis of such assertion. If such written objection is timely made, the Independent Counsel so selected may not serve as Independent Counsel unless and until a court has determined that such objection is without merit. If, within 20 days after submission by Indemnitee of a written request for indemnification pursuant to Section 8(a) hereof, no Independent Counsel shall have been selected and not objected to, either the Company or Indemnitee may petition the Court of Chancery of the State of Delaware or other court of competent jurisdiction for resolution of any objection which shall have been made by the Company or Indemnitee to the other’s selection of Independent Counsel and/or for the appointment as Independent Counsel of a person selected by the Court or by such other person as the Court shall designate, and the person with respect to whom an objection is so resolved or the person so appointed shall act as Independent Counsel under Section 8(b) hereof. The Company shall pay any and all reasonable fees and expenses of Independent Counsel incurred by such Independent Counsel in connection with acting pursuant to Section 8(b) hereof, and the Company shall pay all reasonable fees and expenses incident to the procedures of this Section 8(c), regardless of the manner in which such Independent Counsel was selected or appointed. Upon the due commencement of any judicial proceeding or arbitration pursuant to Section 10(a)(iii) of this Agreement, Independent Counsel shall be discharged and relieved of any further responsibility in such capacity (subject to the applicable standards of professional conduct then prevailing).

Section 9. Presumptions and Effect of Certain Proceedings.

(a) If a Change of Control shall have occurred, in making a determination with respect to entitlement to indemnification hereunder, the person or persons or entity making such determination shall presume that Indemnitee is entitled to indemnification under this Agreement if Indemnitee has submitted a request for indemnification in accordance with Section 8(a) of this Agreement, and the Company shall have the burden of proof to overcome that presumption in connection with the making by any person, persons or entity of any determination contrary to that presumption.

(b) If the person, persons or entity empowered or selected under Section 8 of this Agreement to determine whether Indemnitee is entitled to indemnification shall not have made a determination within 60 days after receipt by the Company of the request therefor, the requisite determination of entitlement to indemnification shall be deemed to have been made and Indemnitee shall be entitled to such indemnification, absent (i) a misstatement by Indemnitee of a material fact, or an omission of a material fact necessary to make Indemnitee’s statement not materially misleading, in connection with the request for indemnification, or (ii) a prohibition of such indemnification under applicable law; provided, however, that such 60-day period may be extended for a reasonable time, not to exceed an additional 30 days, if the person, persons or entity making the determination with respect to entitlement to indemnification in good faith requires such additional time for the obtaining or evaluating of documentation and/or information relating thereto; and provided, further, that the foregoing provisions of this Section 9(b) shall not apply (i) if the determination of entitlement to indemnification is to be made by the stockholders pursuant to Section 8(b) of this Agreement and if (A) within 15 days after receipt by the Company of the

request for such determination the Board of Directors, or Disinterested Directors, as appropriate, resolve to submit such determination to the stockholders for their consideration at an annual meeting thereof to be held within 90 days after such receipt and such determination is made thereat, or (B) a special meeting of stockholders is called within 60 days after such receipt for the purpose of making such determination, such meeting is held for such purpose within 90 days after having been so called and such determination is made thereat, or (ii) if the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 8(b) of this Agreement.

(c) The termination of any Proceeding or of any claim, issue or matter therein, by judgment, order, settlement or conviction, or upon a plea of nolo contendere or its equivalent, shall not (except as otherwise expressly provided in this Agreement) of itself adversely affect the right of Indemnitee to indemnification or create a presumption that Indemnitee did not act in good faith and in a manner which he reasonably believed to be in or not opposed to the best interests of the Company or, with respect to any criminal Proceeding, that Indemnitee had reasonable cause to believe that his conduct was unlawful.

Section 10. Remedies of Indemnitee.

(a) In the event that (i) a determination is made pursuant to Section 8 of this Agreement that Indemnitee is not entitled to indemnification under this Agreement, (ii) advancement of Expenses is not timely made pursuant to Section 7 of this Agreement, (iii) the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 8(b) of this Agreement and such determination shall not have been made and delivered in a written opinion within 90 days after receipt by the Company of the request for indemnification, (iv) payment of indemnification is not made pursuant to Section 6 of this Agreement within 10 days after receipt by the Company of a written request therefor, or (v) payment of indemnification is not made within 10 days after a determination has been made that Indemnitee is entitled to indemnification or such determination is deemed to have been made pursuant to Section 8 or 9 of this Agreement, Indemnitee shall be entitled to an adjudication in an appropriate court of the State of Delaware, or in any other court of competent jurisdiction, of his entitlement to such indemnification or advancement of Expenses. Alternatively, Indemnitee, at his option, may seek an award in arbitration to be conducted by a single arbitrator pursuant to the then-prevailing Commercial Arbitration Rules of the American Arbitration Association. The parties agree that all matters subject to the arbitration, including the arbitration itself, shall remain confidential. Indemnitee shall commence such proceeding seeking an adjudication or an award in arbitration within 180 days following the date on which Indemnitee first has the right to commence such proceeding pursuant to this Section 10(a); provided, however, that the foregoing clause shall not apply in respect of a proceeding brought by an Indemnitee to enforce his rights under Section 5 of the Agreement.

(b) If a Change of Control shall have occurred, (i) in the event that a determination shall have been made pursuant to Section 8 of this Agreement that Indemnitee is not entitled to indemnification, any judicial proceeding or arbitration commenced pursuant to this Section 10 shall be conducted in all respects as a de novo trial, or arbitration, on the merits and Indemnitee shall not be prejudiced by reason of that adverse determination; and (ii) in any judicial proceeding or arbitration commenced pursuant to this Section 10 the Company shall have the

burden of proving that Indemnitee is not entitled to indemnification or advancement of Expenses, as the case may be.

(c) If a determination shall have been made or deemed to have been made pursuant to Section 8 or 9 of this Agreement that Indemnitee is entitled to indemnification, the Company shall be bound by such determination in any judicial proceeding or arbitration commenced pursuant to this Section 10, absent (i) a misstatement by Indemnitee of a material fact, or an omission of a material fact necessary to make Indemnitee’s statement not materially misleading, in connection with the request for indemnification, or (ii) a prohibition of such indemnification under applicable law.

(d) The Company shall be precluded from asserting in any judicial proceeding or arbitration commenced pursuant to this Section 10 that the procedures and presumptions of this Agreement are not valid, binding and enforceable and shall stipulate in any such court or before any such arbitrator that the Company is bound by all the provisions of this Agreement.

(e) In the event that Indemnitee, pursuant to this Section 10, seeks a judicial adjudication of or an award in arbitration to enforce his rights under, or to recover damages for breach of, this Agreement, Indemnitee shall be entitled to recover from the Company, and shall be indemnified by the Company against, any and all expenses (of the types described in the definition of Expenses in Section 17 of this Agreement) actually and reasonably incurred by him in such judicial adjudication or arbitration, but only if he prevails therein. If it shall be determined in said judicial adjudication or arbitration that Indemnitee is entitled to receive part but not all of the indemnification or advancement of expenses sought, the expenses incurred by Indemnitee in connection with such judicial adjudication or arbitration shall be appropriately prorated in good faith by counsel for Indemnitee.

Section 11. Non-Exclusivity; Survival of Rights; Insurance; Subrogation.

(a) The rights of indemnification and to receive advancement of Expenses as provided by this Agreement shall be in addition to, and shall not be deemed exclusive of, any other rights to which Indemnitee may at any time be entitled under applicable law, the Certificate of Incorporation or the By-Laws of the Company, any agreement, a vote of stockholders or a resolution of directors, or otherwise. No amendment, alteration or repeal of this Agreement or of any provision hereof shall limit or restrict any right of Indemnitee under this Agreement in respect of any action taken or omitted by such Indemnitee in his Corporate Status prior to such amendment, alteration or repeal.

(b) To the extent that the Company maintains an insurance policy or policies providing liability insurance for directors, officers or employees of the Company or of any other corporation, partnership, limited liability company, joint venture, trust, employee benefit plan or other enterprise which such person serves at the request of the Company, Indemnitee shall be covered by such policy or policies in accordance with its or their terms to the maximum extent of the coverage available for any such similarly situated director, officer or employee under such policy or policies.

(c) In the event of any payment by the Company under this Agreement, the Company shall be subrogated to the extent of such payment to all of the rights of recovery of Indemnitee, who shall execute all papers required and take all action necessary to secure such rights, including execution of such documents as are necessary to enable the Company to bring suit to enforce such rights.

(d) The Company shall not be liable under this Agreement to make any payment of amounts otherwise indemnifiable hereunder if and to the extent that Indemnitee has otherwise actually received such payment under any Bylaw, insurance policy, contract, agreement or otherwise.

Section 12. Certain Settlement Provisions . The Company shall have no obligation to indemnify Indemnitee under this Agreement for amounts paid in settlement of a Proceeding without the Company’s prior written consent. The Company shall not settle any Proceeding in any manner that would impose any fine, Expense, limitation or other obligation on Indemnitee without Indemnitee’s prior written consent. Neither the Company nor Indemnitee shall unreasonably withhold their consent to any proposed settlement.

Section 13. Duration of Agreement. This Agreement shall continue for so long as the Indemnitee may have any liability or potential liability by virtue of serving as a director, officer or employee of the Company or of any other corporation, partnership, limited liability company, joint venture, trust, employee benefit plan or other enterprise which Indemnitee served at the request of the Company, including without limitation, the final termination of all pending Proceedings in respect of which Indemnitee is granted rights of indemnification or advancement of expenses hereunder and of any proceeding commenced by Indemnitee pursuant to Section 10 of this Agreement relating thereto. This Agreement shall be binding upon the Company and its successors and assigns and shall inure to the benefit of Indemnitee and his heirs, executors, legal representatives and administrators.

Section 14. Severability. If any provision or provisions of this Agreement shall be held to be invalid, illegal or unenforceable for any reason whatsoever: (a) the validity, legality and enforceability of the remaining provisions of this agreement (including without limitation, each portion of any Section of this Agreement containing any such provision held to be invalid, illegal or unenforceable) shall not in any way be affected or impaired thereby; and (b) to the fullest extent possible, the provisions of this Agreement (including, without limitation, each portion of any Section of this Agreement containing any such provision held to be invalid, illegal or unenforceable, that is not itself invalid, illegal or unenforceable) shall be construed so as to give effect to the intent manifested by the provision held invalid, illegal or unenforceable.

Section 15. Exception to Right of Indemnification or Advancement of Expenses. Notwithstanding any other provision of this Agreement, Indemnitee shall not be entitled to indemnification or advancement of Expenses under this Agreement with respect to (i) any Proceeding, or any claim therein, brought or made by him against the Company except for any claim or proceeding or in respect of this Agreement and/or the Indemnitee’s rights hereunder; or (ii) the payment by Indemnitee to the Company of profits pursuant to Section 16(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or Proceedings in connection therewith.

Section 16. Identical Counterparts. This Agreement may be executed in one or more counterparts, each of which shall for all purposes be deemed to be an original but all of which together shall constitute one and the same Agreement. Only one such counterpart signed by the party against whom enforceability is sought needs to be produced to evidence the existence of this Agreement. Signatures to this Agreement transmitted by facsimile transmission, by electronic mail in “portable document format” (.pdf) form, or by any other electronic means intended to preserve the original graphic and pictorial appearance of a document, will have the same effect as physical delivery of the paper document bearing the original signature.

Section 17. Headings. The headings of the paragraphs of this Agreement are inserted for convenience only and shall not be deemed to constitute part of this Agreement or to affect the construction thereof.

Section 18. Definitions.

(a) “Change of Control” means:

(I) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 35% or more of either (1) the then outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (2) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however , that for purposes of this subsection (I), the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any entity controlled by the Company or (iv) any acquisition by any entity pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (III) of this definition; or

(II) Individuals who, as of the date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however , that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

directors, as the case may be, of the entity resulting from such Business Combination (including, without limitation, an entity that as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (excluding any entity resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting from such Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common equity of the entity resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such entity except to the extent that such ownership existed prior to the Business Combination and (3) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non-corporate entity, resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

(IV) Approval by the stockholders of the Company of a complete liquidation or dissolution of the Company, other than a liquidation or dissolution in connection with a transaction to which subsection (III) applies.

(b) “Corporate Status” describes the status of a person who is or was a director, officer or employee of the Company or of any other corporation, partnership, limited liability company, joint venture, trust, employee benefit plan or other enterprise which such person is or was serving at the request of the Company.

(c) “Disinterested Director” means a director of the Company who is not and was not a party to the Proceeding in respect of which indemnification is sought by Indemnitee.

(d) “Expenses” shall include all reasonable attorneys’ fees, retainers, court costs, transcript costs, fees of experts, witness fees, travel expenses, duplicating costs, printing and binding costs, telephone charges, postage, delivery service fees, and all other disbursements or expenses of the types customarily incurred in connection with prosecuting, defending, preparing to prosecute or defend, investigating, participating or being or preparing to be a witness in a Proceeding.

(e) “Independent Counsel” means a law firm, or a member of a law firm, that is experienced in matters of corporation law and neither presently is, nor in the past five years has been, retained to represent: (i) the Company or Indemnitee in any matter material to either such party (other than as Independent Counsel under this Agreement or similar agreements), or (ii) any other party to the Proceeding giving rise to a claim for indemnification hereunder. Notwithstanding the foregoing, the term “Independent Counsel” shall not include any person who, under the applicable standards of professional conduct then prevailing, would have a conflict of interest in representing either the Company or Indemnitee in an action to determine Indemnitee’s rights under this Agreement.

(f) “Proceeding” includes any action, suit, arbitration, alternate dispute resolution mechanism, investigation, administrative hearing or any other proceeding whether civil, criminal, administrative or investigative.

Section 19. Modification and Waiver. No supplement, modification or amendment of this Agreement shall be binding unless executed in writing by both of the parties hereto. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a wavier of any other provisions hereof (whether or not similar) nor shall such waiver constitute a continuing waiver.

Section 20. Notice by Indemnitee. Indemnitee agrees promptly to notify the Company in writing upon being served with any summons, citation, subpoena, complaint, indictment, information or other document relating to any Proceeding or matter which may be subject to indemnification or advancement of Expenses covered hereunder.

Section 21. Notices. All notices, requests, demands and other communications hereunder shall be in writing and shall be deemed to have been duly given if (i) delivered by hand and received for by the party to whom said notice or other communication shall have been directed, or (ii) mailed by certified or registered mail with postage prepaid, on the third business day after the date on which it is so mailed:

(a) If to Indemnitee, to his address on file with the Company from time to time.

(b) If to the Company to:

840 Gessner Road, Suite 1400

Houston, Texas 77024

or to such other address as may have been furnished to Indemnitee by the Company or to the Company by Indemnitee, as the case may be.

Section 22. Governing Law. The parties agree that this Agreement shall be governed by, and construed and enforced in accordance with, the laws of the State of Delaware.

Section 23. Miscellaneous. Use of the masculine pronoun shall be deemed to include usage of the feminine pronoun where appropriate.

Section 24. Disclosure . In certain instances, applicable law (including applicable federal law that may preempt or override applicable state law) or public policy may prohibit the Company from indemnifying the directors and officers of the Company under this Agreement or otherwise. For example, the U.S. Securities and Exchange Commission has taken the position that indemnification of directors, officers and controlling persons of the Company for liabilities arising under federal securities laws is against public policy and, therefore, unenforceable. The Company has undertaken or may be required in the future to undertake with the Securities and Exchange Commission to submit the question of indemnification to a court in certain circumstances for a determination of the Company’s right under public policy to indemnify Indemnitee. In addition, federal law prohibits indemnification for certain violations of the Employee Retirement Income Security Act of 1974, as amended.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement on the day and year first above written.

ATTEST:		CABOT OIL & GAS CORPORATION


By		By:
	Deidre L. Shearer		Dan O. Dinges
	Corporate Secretary		Chairman, President and CEO


		INDEMNITEE


		By:


		Address:

Exhibit 10.6

CABOT OIL & GAS CORPORATION
2004 INCENTIVE PLAN

NON-EMPLOYEE DIRECTOR RESTRICTED STOCK UNIT AWARD AGREEMENT

THIS AGREEMENT (“Agreement”), made as of [ grant date ] (the “Grant Date”), evidences an award by CABOT OIL & GAS CORPORATION, a Delaware corporation (the “Company”), to [ Participant Name ] (the “Grantee”), a non-employee director of the Company, pursuant to the Cabot Oil & Gas Corporation 2004 Incentive Plan (the “Plan”). Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

1. Grant of Restricted Stock Units . Effective as of the Grant Date, pursuant to Paragraph 8(a)(ii) of the Plan, the Company has awarded to the Grantee Restricted Stock Units representing a total of [ number of shares granted ] shares of Common Stock, subject to the conditions and restrictions set forth below and in the Plan (the “Restricted Stock Units”).

2. Restrictions . The Restricted Stock Units granted hereunder to the Grantee may not be sold, assigned, transferred, pledged or otherwise encumbered unless and until the date that the Grantee obtains the rights of a Stockholder as described in Section 9 of this Agreement. The Grantee shall have a vested right to all of the Restricted Stock Units as of the Grant Date; provided, however, that Common Stock to which such Restricted Stock Units relate shall not be deliverable to the Grantee until the date that the Grantee ceases to be a director of the Board of Directors of the Company and has a separation from service within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (“Code’) with respect to such Restricted Stock Units (the “Termination Date”).

3. Dividend Credits . During the period of time between the Grant Date and the date on which Grantee receives a distribution of the shares of Common Stock related to the Restricted Stock Units awarded hereunder, the Award of Restricted Stock Units hereunder shall be evidenced by book entry registration. As of each date that dividends are paid with respect to Common Stock (the “Dividend Payment Date”), the Grantee shall have an amount credited to his account equal to the amount of the dividend paid per share of Common Stock as of such Dividend Payment Date multiplied by the number of Restricted Stock Units credited to the Grantee’s account immediately prior to such Dividend Payment Date. Such amount shall be paid to the Grantee on the 15th business day following the Dividend Payment Date.

4. Beneficiary Designations . The Grantee shall file with the Secretary of the Company on such form as may be prescribed by the Company, a designation of one or more beneficiaries and, if desired, one or more contingent beneficiaries (each referred to herein as a “Beneficiary”) to whom shares of Common Stock otherwise due the Grantee under the terms of this Agreement shall be distributed in the event of the death of the Grantee. The Grantee shall have the right to change the Beneficiary or Beneficiaries from time to time; provided, however, that any change shall not become effective until received in writing by the Secretary of the Company. If any designated Beneficiary survives the Grantee but dies after the Grantee’s death, any remaining benefits due such deceased Beneficiary under this Agreement shall be distributed to the personal representative or executor of the deceased Beneficiary’s estate. If there is no

effective Beneficiary designation on file at the time of the Grantee’s death, or if the designated Beneficiary or Beneficiaries have all predeceased such Grantee, the payment of any remaining benefits under this Agreement shall be made to the personal representative or executor of the Grantee’s estate. If one or more but not all the Beneficiaries have predeceased such Grantee, the benefits under this Agreement shall be paid according to the Grantee’s instructions in his designation of Beneficiaries. If the Grantee has not given instructions, or if the instructions are not clear, the benefits under this Agreement which would have been paid to the deceased Beneficiary or Beneficiaries will be paid to the personal representative or executor of Grantee’s estate.

5. Nonalienation of Benefits . Except as contemplated by Section 4 above, no right or benefit under this Agreement shall be subject to transfer, anticipation, alienation, sale, assignment, pledge, encumbrance or charge, whether voluntary, involuntary or by operation of law, and any attempt to transfer, anticipate, alienate, sell, assign, pledge, encumber or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to any debts, contracts, liabilities or torts of the .person entitled to such benefits. If the Grantee or the Grantee’s Beneficiary hereunder shall become bankrupt or attempt to transfer, anticipate, alienate, assign, sell, pledge, encumber or charge any right or benefit hereunder, other than as contemplated by Section 4 above, or if any creditor shall attempt to subject the same to a writ of garnishment, attachment, execution, sequestration or any other form of process or involuntary lien or seizure, then such right or benefit shall cease and terminate.

6. Prerequisites to Benefits . Neither the Grantee, nor any person claiming through the Grantee, shall have any right or interest in Restricted Stock Units awarded hereunder or the shares of Common Stock related thereto, unless and until all the terms, conditions and provisions of this Agreement and the Plan which affect the Grantee or such other person shall have been complied with as specified herein.

7. Payment . Upon satisfaction of all the terms, conditions and provisions of this Agreement and the Plan, a Restricted Stock Unit credited to the Grantee’s account shall be payable to the Grantee in the form of one share of Common Stock on the 15th business day following the Termination Date; provided, however, that if, on the Termination Date, Grantee is treated by the Company as a “specified employee” within the meaning of Section 409A of the Code, then any such payment shall be made on the 15th business day following the earlier of (i) the expiration of six months from the Termination Date or (ii) the Grantee’s death (“409A Payment Date”) but, in any event, no later than the last day of the calendar year in which the 409A Payment Date occurs.

8. Restrictions on Delivery of Shares . The Company shall not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such issuance or delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. If necessary to comply with any such law, rule, regulation or agreement, the Company shall in no event be obligated to take any affirmative action in order to cause the delivery of shares of Common Stock.

9. Rights as a Stockholder . The Grantee (or Beneficiary) shall have no rights as a stockholder with respect to the shares of Common Stock represented by the Restricted Stock Units unless and until all the terms, conditions and provisions of this Agreement and the Plan which affect the Grantee or such other person shall have been complied with as specified herein, and certificates evidencing such shares are delivered to the Grantee pursuant to Section 7 hereof.

10. Adjustments . As provided in Paragraph 15 (Adjustments) of the Plan, certain adjustments may be made to the Restricted Stock Units upon the occurrence of events or circumstances described in Paragraph 15 of the Plan.

11. Notice . Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be:

(a) delivered personally to the following address:

Cabot Oil & Gas Corporation

c/o Corporate Secretary

840 Gessner, Suite 1400

Houston, Texas 77024

(b) sent by first class mail, postage prepaid and addressed as follows:

Cabot Oil & Gas Corporation

c/o Corporate Secretary
840 Gessner, Suite 1400
Houston, Texas 77024

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, or shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address.

12. Amendment . Without the consent of the Grantee, this Agreement may be amended or supplemented (i) to cure any ambiguity or to correct or supplement any provision herein which may be defective or inconsistent with any other provision herein, or (ii) to add to the covenants and agreements of the Company for the benefit of Grantee or to add to the rights of the Grantee or to surrender any right or power reserved to or conferred upon the Company in this Agreement, subject, however, to any required approval of the Company’s stockholders and, provided, in each case, that such changes or corrections shall not adversely affect the rights of Grantee with respect to the Award evidenced hereby without the Grantee’s consent, or (iii) to make such other changes as the Company, upon advice of counsel, determines are necessary or advisable because of the adoption or promulgation of, or change in or of the interpretation of, any law or governmental rule or regulation, including any applicable federal or state securities laws.

13. Grantee Service . Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue as a director of the Company or any Subsidiary.

14. Governing Law . This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware.

15. Section 409A Compliance. The following provisions shall apply to this Agreement, notwithstanding any provision to the contrary:

(a) This Agreement is intended to comply with Section 409A of the Code and ambiguous provisions, if any, shall be construed in a manner that is compliant with or exempt from the application of Section 409A.

(b) This Agreement shall not be amended or terminated in a manner that would cause the Agreement or any amounts payable under the Agreement to fail to comply with the requirements of Section 409A, to the extent applicable, and, further, the provisions of any purported amendment that may reasonably be expected to result in such non-compliance shall be of no force or effect with respect to the Agreement.

(c) The Company shall neither cause nor permit any payment, benefit or consideration to be substituted for a benefit that is payable under this Agreement if such action would result in the failure of any amount that is subject to Section 409A to comply with the applicable requirements of Section 409A.

(d) The Company shall neither cause nor permit any adjustments to any equity interest to be made in a manner that would result in the equity interest’s becoming subject to Section 409A unless, after such adjustment, the equity interest is in compliance with the requirements of Section 409A to the extent applicable.

(e) For purposes of Section 409A, each payment under this Agreement shall be deemed to be a separate payment.

16. Construction . References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all Exhibits and Schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan. The headings of the Sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

17. Relationship to the Plan . In addition to the terms and conditions described in this Agreement, grants of Restricted Stock Units are subject to all other applicable provisions of the Plan. The decisions of the Committee with respect to questions arising as to the interpretation of the Plan, or this Agreement and as to finding of fact, shall be final, conclusive and binding.

	CABOT OIL & GAS CORPORATION


	By:	/s/ Scott C. Schroeder
	Name:	Scott C. Schroeder
	Title:	Vice President, Chief Financial Officer & Treasurer


	By:
		[ Participant Name ]

Exhibit 10.7(a)

RESTRICTED STOCK AWARD AGREEMENT

THIS AGREEMENT, effective as of [ grant date ], between Cabot Oil & Gas Corporation, a Delaware corporation (the “Company”) and [ Participant Name ] (the “Participant”), is made pursuant to the provisions of the Company’s 2004 Incentive Plan (the “Plan”). The capitalized terms appearing in this Agreement shall have the definitions ascribed to them in the Plan. In the event there is any inconsistency between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall supersede and replace the terms of this Agreement. The parties agree as follows:

1. Terms of Grant . Participant is hereby awarded [ number of shares granted ] shares of Cabot Oil & Gas Corporation Common Stock, par value $.10/share, with such restrictions thereon as described below (the “Restricted Stock”). The date of such grant is [ grant date ] (“Date of Grant”). Subject to the terms and provisions of this Agreement, such restrictions shall lapse (i) with respect to 1/3 of the shares of Restricted Stock as of the first anniversary of the Date of Grant; (ii) with respect to 1/3 of the shares of Restricted Stock as of the second anniversary of the Date of Grant, and (iii) with respect to the remaining 1/3 of the shares of Restricted Stock as of the third anniversary of the Date of Grant (“Date of Lapse of Restrictions”). The period from the Date of Grant and until the Date of Lapse of Restrictions shall be referred to herein as the “Period of Restriction”.

2. Employment by the Company . The shares of Restricted Stock are awarded on the condition that the Participant remain in the employ of the Company from the Date of Grant through and including the Date of Lapse of Restrictions.

However, neither such condition nor the award of this Restricted Stock shall impose upon the Company any obligation to retain the Participant in its employ for any given period or upon any specific terms of employment.

3. Stock Certificate . Once the restrictions have lapsed in accordance with the terms of this Agreement, the Restricted Stock may be deposited into a brokerage account set up in the Participant’s name as may be designated by the Corporate Secretary. Alternatively, such shares may be delivered to the Participant in certificate or DRS form. In each instance, the number of shares issued shall be reduced by the Participant’s Federal, State and Local tax obligations (including FICA) required by the law to be withheld, unless other arrangements for tax withholding are made.

4. Removal of Restrictions . Except as otherwise provided in the Plan, shares of Restricted Stock granted under this Agreement shall become freely transferable by the Participant after the Date of Lapse of Restrictions.

5. Voting Rights and Dividends . During the Period of Restrictions, the Participant may not exercise voting rights and is not entitled to receive any dividends and other distributions paid with respect to his or her Restricted Stock.

6. Termination of Employment . Except as otherwise provided in this Section 6, in the event the Participant’s employment is terminated prior to a Date of Lapse of Restrictions, all then-unvested shares of Restricted Stock shall immediately be forfeited by the Participant unless otherwise determined by the Committee. In the case of the termination of employment by reason of death or disability, all shares of Restricted Stock shall, to the extent not previously vested, become fully vested. In the case of the termination of employment for any other reason, the Compensation Committee may, in its sole discretion, accelerate the vesting of some or all unvested shares of Restricted Stock, upon such terms as the Compensation Committee deems advisable.

7. Change in Control . In the event of a Change in Control (as herein defined), any restriction periods and restrictions imposed on the shares of Restricted Stock subject to this Agreement shall lapse, and within ten (10) business days after the occurrence of a Change in Control (as herein defined), the stock certificates representing the shares of Restricted Stock, without any restrictions or legend thereon, shall be delivered to the Participant.

“Change in Control” shall mean :

(I) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 35% or more of either (1) the then outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (2) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that for purposes of this subsection (I), the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any entity controlled by the Company or (iv) any acquisition by any entity pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (III) of this definition; or

(II) Individuals who, as of the date hereof, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the entity resulting from such Business Combination (including, without limitation, an entity that as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (excluding any entity resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting from such Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common equity of the entity resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such entity except to the extent that such ownership existed prior to the Business Combination and (3) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non-corporate entity, resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

8. Transferability . This Restricted Stock is not transferable by the Participant, whether voluntarily, involuntarily or by operation of law or otherwise during the Period of Restriction, except as provided in the Plan. If any assignment, pledge, transfer, or other disposition, voluntary or involuntary, of this Restricted Stock shall be made, or if any attachment, execution, garnishment, or lien shall be issued against or placed upon the Restricted Stock, then the Participant’s right to the Restricted Stock shall immediately cease and terminate.

9. Recapitalization . In the event of any merger, reorganization, consolidation, recapitalization, separation, liquidation, stock dividend, split-up, share combination, or other change in the corporate structure of the Company affecting the shares of Restricted Stock, the number of shares of Restricted Stock subject to this Agreement shall be equitably adjusted by the Compensation Committee to prevent dilution or enlargement of rights.

10. Administration . This Agreement and the rights of the Participant hereunder are subject to all of the terms and conditions of the Plan, as the same may be amended from time to time, as well as to such rules and regulations as the Compensation Committee may adopt for administration of the Plan. It is expressly understood that the Compensation Committee is authorized to administer, construe and make all determinations necessary or appropriate to the administration of the Plan and this Agreement, all of which shall be binding upon the Participant.

11. Miscellaneous .

(a) This Agreement shall not confer upon the Participant any right to continuation of employment by the Company; nor shall this Agreement interfere in any way with the Company’s right to terminate his or her employment at any time.

(b) With the approval of the Board of Directors, the Compensation Committee may terminate, amend or modify the Plan; provided, however, that no such termination, amendment or modification of the Plan may in any material way adversely affect the Participant’s rights under this Agreement.

(c) This Agreement shall be subject to all applicable laws, rules and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.

(d) To the extent not preempted by federal law, this Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware.

IN WITNESS WHEREOF, this Restricted Stock Award Agreement has been executed as of the date first written above.

	Company:

	Cabot Oil & Gas Corporation


	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President, Chief Financial Officer &
		Treasurer

	Participant:


	By:	[ Participant Name ]

Exhibit 10.7(b)

Stock Appreciation Rights Agreement

The Company, desiring to afford you, [ Participant Name ], an opportunity to acquire shares of Cabot Oil & Gas Corporation Common Stock, par value $.10 per share (“Common Stock”), and to provide you with an added incentive as an employee or consultant of the Company or of one or more of its Subsidiaries, has established the following terms and conditions under which it has granted to you stock appreciation rights (“SARs”) under the Cabot Oil & Gas Corporation 2004 Incentive Plan (the “Plan”). Each SAR will allow you to receive a number of shares of Common Stock during a specified term, subject to and upon the terms and conditions set forth herein.

1. Specification of Date, Number of SARs, Grant Date Price, and Term .

(a) The grant date of the SARs is [ February 16, 2012 ].

(b) The number of SARs granted to you hereby is [ number of shares granted ], subject to adjustments under Section 15 of the Plan.

(c) Subject to adjustments under Sections 6 and 8, the SARs first become exercisable (i) with respect to 33 1/3% of the total number of SARs, as of the first anniversary of the date of grant of the SARs; and (ii) with respect to an additional 33 1/3% of the total number of SARs, as of the second anniversary of the date of grant of the SARs; and (iii) with respect to the remaining 33 1/3% of the total number of SARs, as of the third anniversary of the date of grant of the SARs.

(d) The grant date price per share applicable to the SARs (the “Grant Date Price”) is [ $35.18 ], subject to adjustments under Section 15 of the Plan.

(e) The term of the SARs expires on [ February 16, 2019 ]. Upon the expiration of such term, the SARs shall expire and terminate and may not be exercised.

2. Agreement . By accepting the SARs and the benefits thereof, you represent and agree that you will abide by the terms of the Plan and such other terms and conditions as may be imposed by the committee appointed by the board of directors to administer the Plan (the “Committee”).

3. Installment Provisions and Acceleration . The SARs are not exercisable in any part until the earliest of the dates specified in this Paragraph and in Paragraphs 6 and 8 below.

The installments set forth in Paragraph 1(c) are cumulative, so that each matured installment or any portion thereof may be exercised at any time until the expiration or prior termination of the SARs.

Nothing contained in this section shall be interpreted in a way that permits you to exercise a number of SARs in excess of the number of SARs granted hereby and referred to in Paragraph 1(b).

4. Method of Exercise . The SARs may be exercised from time to time, in accordance with their terms, by written notice thereof signed and delivered by you or another person entitled to exercise the SARs to the Corporate Secretary of the Company at its principal executive office in Houston, Texas, or as it may hereafter be located, or to such brokerage firm, third-party agent or other person as may be designated by the Corporate Secretary from time to time. Such notice shall state the number of SARs being exercised and the grant date of the SARs being exercised.

Promptly after receipt of such notice, the Company shall issue and deliver to you whole shares of Common Stock equal in number to the product of A multiplied by B and then divided by C, where A is the number of vested SARs exercised, B is the result of subtracting the Grant Date Price from the per-share Fair Market Value of the Common Stock prevailing at the time of exercise as defined by the Plan, and C is the per-share Fair Market Value of the Common Stock prevailing at the time of exercise as defined by the Plan. Any fractional shares resulting from this calculation shall be valued at the per-share Fair Market Value of the Common Stock prevailing at the time of exercise as defined by the Plan and paid to you in cash if there is no withholding requirement as a result of the exercise; if there is a withholding requirement, said cash amount will be applied toward satisfying the withholding requirement.

Upon exercise of any of the SARs and at your election, the Company will withhold from the shares of Common Stock to be delivered shares with a Fair Market Value (as prescribed by the Plan) sufficient to satisfy all or a portion of any federal, state and local tax withholding requirements, or the person exercising the SARs may deliver to the Company cash sufficient to satisfy all or a portion of such tax withholding requirements.

5. Transferability . The SARs are not transferable by you, whether voluntarily, involuntarily or by operation of law or otherwise, except as provided in the Plan. If any assignment, pledge, transfer, or other disposition, voluntary or involuntary, of the SARs shall be made, or if any attachment, execution, garnishment, or lien shall be issued against or placed upon the SARs, then your right to the SARs shall immediately cease and terminate.

6. Termination of Employment or Service .

(a) If your employment is terminated by reason of retirement under an approved retirement program (“Retirement”) or Disability (as hereinafter defined), the SARs granted hereby, to the extent not previously exercised, shall become fully vested and exercisable on the date of such termination, irrespective of the limitations described in Paragraph 1(c), and you shall have the right to exercise the SARs at any time on or prior to the earlier of (i) the end of the 36 month period commencing on the day next following such termination and (ii) the expiration of the term of the SARs as set forth in Paragraph 1(e). “Disability” as used herein shall mean sickness or injury that causes an individual to be unable to perform the duties of his regular job or termination or placement by the Company of the individual on medical leave of absence pursuant to a disability plan or program sponsored or maintained by the Company. Notwithstanding the foregoing and in the case of a retirement, you must be an employee of the Company on September 30 th of the year the award is granted in order to vest in the award.

(b) If your employment is terminated for reasons other than as stated in 6(a) above, the SARs shall be exercisable by you only within 90 days after such termination, and only to the extent they were exercisable immediately prior to the date of termination; provided, however, that notwithstanding the foregoing, to the extent your termination of employment is involuntary and to the extent the SARs were exercisable immediately prior to such involuntary termination of employment, the Committee may, in its discretion, extend such 90 day period up to but not to exceed in the aggregate 36 months.

(c) In the event of your death, the SARs granted hereby, to the extent not previously exercised, shall become fully vested and exercisable on the date of your death, irrespective of the limitations described in Paragraph 1(c), and your personal representatives, heirs, legatees or distributees shall have the right to exercise the SARs at any time on or prior to the earlier of (i) the end of the 36 month period commencing on the day next following the date of death and (ii) the expiration of the term of the SARs as set forth in Paragraph 1(e).

(d) Anything contained in this Agreement to the contrary notwithstanding, (i) the SARs shall not be exercisable after the expiration date specified in Paragraph 1(e), hereof; and (ii) if you have the right to exercise the SARs but are not able to do so because of legal incapacity, then the exercise of such SARs may be accomplished through your duly authorized representative.

7. Confidential Information and Non-Competition. In consideration of (i) the Company disclosing and providing access to Confidential Information, as more fully described in Section 7(a) below, (ii) the grant by the Company of the SARs to provide an economic incentive to Employee to use Employee’s best efforts during his/her employment with the Company to advance the business and goodwill of the Company and in order to protect the Company’s interests in its Confidential Information and goodwill after the date hereof, and (iii) other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Employee, intending to be legally bound, hereby agrees as follows:

(a) You hereby covenant and agree that at all times during your employment with the Company and for a period of twenty-nine (29) months after a termination of the your employment by reason of Retirement as provided in Paragraph 6, you will not, without the prior written consent of the Company’s chief legal officer, either directly or indirectly, for yourself or on behalf of or in conjunction with any other person, company, partnership, corporation or other entity, engage in any activities prohibited in the following subsections (1) through (3) of this Paragraph 7(a):

(1) You shall not assist or directly or indirectly provide services, whether as a partner, employee, consultant, officer, director, manager, agent, associate, investor, or otherwise, to any person or entity which is at the time of such assistance or provision a “Competitor” of the Company. For purposes of this Paragraph 7, the term “Competitor” means any person or entity that is engaged in the exploration and production of oil, gas or other hydrocarbons, the transportation thereof, any other midstream activities or the provision of oilfield

services in any state or county/parish thereof in which the Company conducts business and/or has established business plans to conduct business activities within the twelve month period preceding your termination.

(2) In order to assist you with your duties, the Company shall continue to provide you with access to confidential and proprietary information and other confidential information which is either information not known by actual or potential competitors, customers and third parties of the Company or is proprietary information of the Company (“Confidential Information”). Such Confidential Information shall include all non-public information you acquired as a result of your positions with the Company that might be of any value to a competitor of the Company. Examples of such Confidential Information include, without limitation, non-public information about the Company’s customers, suppliers, and potential acquisition targets; its business operations, structure and methods of operation; its services and pricing; its processes, machines and inventions; its research and know-how; its business planning and strategies; information maintained in its computer systems; devices, processes, compilations of information and records; and future business plans. You agree that such Confidential Information remains confidential even if committed to your memory. You agree not to use, divulge, or furnish or make accessible to any third party, company, corporation or other organization (including but not limited to customers, competitors, or governmental agencies), without the Company’s prior written consent, any Confidential Information of the Company, except as necessary in performing your duties on behalf of the Company during your employment with the Company. Your obligations under this Paragraph will not apply to the extent that (i) the disclosure of Confidential Information is required by applicable law; provided, however, that, prior to disclosing such Confidential Information, to the fullest extent practicable you must notify the Company thereof, which notice will include the basis upon which you believe the information is required to be disclosed, or (ii) information otherwise determined to be Confidential Information is or becomes generally available to the public or to persons generally knowledgeable in the Company’s industry without violation of this Agreement by you.

(3) You agree that whenever your employment with the Company ends for any reason, (i) all documents containing or referring to the Company’s Confidential Information as may be in your possession, or over which you may have control, and all other property of the Company provided to you by the Company during the course of your employment with the Company will be returned to the Company immediately, with no request being required; and (ii) all Company computer and computer-related equipment and software, and all Company property, files, records, documents, drawings, specifications, lists, equipment and similar items relating to the business of the Company, whether prepared by you or otherwise, coming into your possession or control during the course of your employment shall remain the exclusive property of the Company, and shall be delivered by you to the Company immediately, with no request being required.

(b) You specifically recognize and affirm that each of the covenants contained in Paragraphs 7(a)(1) through (3) of this Agreement is a material and important term of this Agreement which has induced the Company to provide for the award of the SARs granted hereunder, the disclosure of the Confidential Information referenced herein, and the other promises made by the Company herein. You further agree that in the event that your employment is terminated by reasons of Retirement as provided in Paragraph 6 and thereafter (A) the Company determines that you have breached any term of Paragraphs 7(a) (1) through (3) or (B) all or any part of Paragraph 7(a) is held or found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction in any action between you and the Company, in addition to any other remedies at law or in equity the Company may have available to it, you shall lose the right to exercise any remaining SARs, and the remaining SARs shall be deemed forfeited effective as of the date (A) the Company determines that you have breached any term of Paragraphs 7(a) or (B) all or any part of Paragraph 7(a) is held or found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction in an action between you and the Company.

(c) You and the Company agree that the restrictions set forth in Paragraph 7(a) are reasonable, including the geographic area, duration as to time, and scope of activities restrained. You further agree that if any covenant contained in Paragraph 7(a) is found by a court of competent jurisdiction to contain limitations as to time, geographical area, or scope of activity that are not reasonable and impose a greater restraint than is necessary to protect the goodwill or other business interest of the Company, then the court shall reform the covenant to the extent necessary to cause the limitations contained in the covenant as to time, geographical area, and scope of activity to be restrained to be reasonable and to impose a restraint that is not greater than necessary to protect the goodwill and other business interests of the Company and to enforce the covenants as reformed.

(d) The covenants made by you in this Paragraph 7 are considered independent of any other agreement, and you understand and agree that the fact that you may have a claim against the Company, whether predicated upon this Agreement or otherwise, is not a defense to enforcement of this Paragraph 7.

8. Change in Control . In the event of a Change in Control (as herein defined), the SARs granted hereby, to the extent not previously exercised, shall become fully vested and exercisable on the date of such Change in Control, irrespective of the limitations described in Paragraph 1(c), and shall remain exercisable throughout the term of the SARs.

For purposes of this Agreement, “Change in Control” shall mean:

(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 35% or more of either (1) the then outstanding shares of common stock of the Company (the

“Outstanding Company Common Stock”) or (2) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that for purposes of this subsection (a), the following acquisitions shall not constitute a Change in Control: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any entity controlled by the Company or (iv) any acquisition by any entity pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (c) of this definition; or

(b) Individuals who, as of the date hereof, constitute the board of directors (“Board”) of the Company (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Company’s stockholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

(c) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company (a “Business Combination”), in each case, unless, following such Business Combination, (1) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the entity resulting from such Business Combination (including, without limitation, an entity that as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (excluding any entity resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting from such Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common equity of the entity resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such entity except to the extent that such ownership existed prior to the Business Combination and (3) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non-corporate entity,

resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

(d) Approval by the stockholders of the Company of a complete liquidation or dissolution of the Company, other than a liquidation or dissolution in connection with a transaction to which subsection (c) applies.

9. Limitation . You or any other person entitled to exercise the SARs shall be entitled to the privileges of stock ownership in respect of shares subject to the SARs only when such shares have been issued and delivered as fully paid shares upon exercise of the SARs in accordance with their terms.

10. Requirements of Law and of Stock Exchanges . The issuance of shares upon the exercise of the SARs shall be subject to compliance with all of the applicable requirements of law with respect to the issuance and sale of such shares. In addition, neither the Company nor any Subsidiary shall be required to issue or deliver any certificate or certificates upon exercise of the SARs prior to the admission of such shares to listing on any stock exchange on which shares of the same class are then listed.

By accepting the SARs, you represent and agree for yourself and your transferees by will or by the laws of descent and distribution or otherwise that unless a registration statement under the U.S. Securities Act of 1933 is in effect as to shares issued upon any exercise of the SARs, any and all shares so issued shall be acquired for investment and not for sale or distribution, and each notice of the exercise of any portion of the SARs shall be accompanied by a representation and warranty in writing, signed by the person entitled to exercise the same, that the shares are being so acquired in good faith for investment and not for sale or distribution. In the event the Company’s legal counsel shall, at the Company’s request, advise it that registration under the U.S. Securities Act of 1933 of the shares as to which the SARs are at the time being exercised is required prior to issuance thereof, neither the Company nor any Subsidiary shall be required to issue or deliver such shares unless and until such legal counsel shall advise that such registration has been completed or is not required.

11. Definition of Certain Terms . The term “you,” and related terms such as “your” used in this Agreement refer to the individual whose name appears in the first paragraph of this Agreement.

12. Continued Employment and Future Grants . Neither the grant of the SARs nor the other arrangements outlined herein give you the right to remain in the employ of or to continue to provide services to the Company or any Subsidiary or to be selected to receive similar or identical grants in the future.

13. Notices . Notice or other communication to the Company with respect to this Agreement must be made in writing and delivered to: Corporate Secretary, Cabot Oil & Gas Corporation, at its principal business office.

14. Governing Law . The SARs and this Agreement shall be governed by, and construed in accordance with, the laws of the state of Delaware.

15. Section 409A of the Code . If any provision of this Agreement would result in the imposition of an excise tax under Section 409A of the Code and related regulations and Treasury pronouncements (“Section 409A”), that provision will be reformed to avoid imposition of the excise tax, and no action taken to comply with Section 409A shall be deemed to impair a benefit under this Agreement.

16. Cabot Oil & Gas Corporation 2004 Incentive Plan . The SARs are subject to, and the Company and you are bound by, all of the terms and conditions of the Plan as the same shall have been amended from time to time in accordance with the terms thereof. Pursuant to such Plan, the Committee is authorized to adopt rules and regulations not inconsistent with the Plan and to take such action in the administration of the Plan as it shall deem proper. A copy of the Plan in its present form is available for inspection at the Company’s principal office during business hours by you or any other persons entitled to exercise the SARs.

In Witness Whereof, this Stock Appreciation Rights Agreement has been executed as of the date first above written.

	Company :

	Cabot Oil & Gas Corporation


	By:	/s/ Scott C. Schroeder
		Scott C. Schroeder
		Vice President, Chief Financial Officer
		& Treasurer


		Employee :


		[ Participant Name ]

Exhibit 10.7(c)

CABOT OIL & GAS CORPORATION

PERFORMANCE SHARE AWARD AGREEMENT

This Performance Share Award Agreement (the “Agreement”), made and entered into by and between Cabot Oil & Gas Corporation (the “Company”) with its principal office at 840 Gessner Road, Suite 1400, Houston, Texas 77024 and [ Participant Name ], (the “Employee”), is dated as of [ grant date ].

As an additional incentive and inducement to the Employee to remain in the employment of the Company or its subsidiaries, and to devote his or her best efforts to the business and affairs of the Company, the Company hereby awards to the Employee a Performance Award of [ number of shares granted ] performance shares (the “Performance Shares”) upon the terms and conditions hereinafter set forth.

This Agreement is expressly subject to the terms and provisions of the Company’s 2004 Incentive Plan (the “Plan”). In the event there is a conflict between the terms of the Plan and this Agreement, the terms of the Plan shall control. All undefined capitalized terms used herein that are not otherwise defined shall have the meanings assigned to them in the Plan.

1. The performance period for the Performance Shares subject to this Agreement shall be the period beginning January 1, 2012 and ending December 31, 2014 (the “Performance Period”).

2. Each Performance Share represents the right to receive, after the end of the Performance Period and based on the Company’s performance, the aggregate of from 0 to 100% of the Fair Market Value of a share of Common Stock payable in Common Stock. The number of shares of Common Stock to be issued shall be determined based on the relevant criteria as of the end of the Performance Period. Cash will be paid in lieu of the issuance of fractional shares of Common Stock. The determination of the amount to be distributed with respect to a Performance Share at the end of the Performance Period shall be based upon the Company’s achievement of performance criteria established by the Committee for the Performance Period as set forth below (the “Performance Criteria”).

There are three (3) Performance Criteria that determine the number of shares of Common Stock of the Company issued per Performance Share. The attainment of one Performance Criterion will result in the receipt of 1/3, the attainment of two Performance Criteria will result in the receipt of 2/3 and the attainment of three Performance Criteria will result in the receipt of 3/3, respectively, of the Performance Shares in shares of Common Stock. The three Performance Criteria for total Company performance are as follows:

(i) 500 MMcfe/d or greater production, averaged over the three year performance period;

(ii) $2.00/MMcfe or below finding costs (all sources), averaged over the three year performance period (oil conversion based on economic rate — oil versus gas); and

(iii) 200% or greater reserve replacement, averaged over the three year performance period.

3. As soon as practicable following the completion of the Performance Period, the Committee shall determine, in writing, the extent to which the Performance Criteria have been met and the amount to be distributed with respect to a Performance Share as provided in Section 2 hereof and the Company shall issue to the Employee the appropriate number of shares of Common Stock. The Committee has sole and absolute authority and discretion to determine the amount to be distributed with respect to Performance Shares. The determination of the Committee shall be binding and conclusive on the Employee. Notwithstanding anything in this Agreement to the contrary, the Employee shall not be entitled to any Common Stock with respect to the Performance Shares unless and until the Committee determines and certifies the extent to which the Performance Criteria have been met.

4. Except as otherwise provided in this Section 4, Section 5, or Section 6, in the event the Employee’s employment is terminated for any reason prior to the completion of the Performance Period, the Performance Shares shall be immediately forfeited unless otherwise determined by the Committee. In the case of the termination of employment by reason of death, disability, or retirement (under a Company approved retirement plan), the Performance Shares shall not be so forfeited and shall otherwise be payable as set forth herein as if such employment continued through the end of the Performance Period. Notwithstanding the foregoing and in the case of a retirement, Employee must be an employee of the Company on September 30 th of the year the award is granted in order to continue vesting in the award. Further, Employee must be an active employee of the Company at the time the Compensation Committee of the Board of Directors certifies the results of the Performance Shares for employment termination other than death, disability or retirement.

5. In consideration of (i) the Company disclosing and providing access to Confidential Information, as more fully described in Section 5(a) below, (ii) the grant by the Company of the Performance Shares to provide an economic incentive to Employee to use Employee’s best efforts during his/her employment with the Company to advance the business and goodwill of the Company and in order to protect the Company’s interests in its Confidential Information and goodwill after the date hereof, and (iii) other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Employee, intending to be legally bound, hereby agrees as follows:

(a) Employee hereby covenants and agrees that at all times during his or her employment with the Company and for a period of twenty-nine (29) months after a termination of the Employee’s employment by reason of retirement as provided in Section 4, he or she will not, without the prior written consent of the Company’s chief legal officer, either directly or indirectly, for himself/herself or on behalf of or in conjunction with any other person, company, partnership, corporation or other entity, engage in any activities prohibited in the following subsections (1) through (3) of this Section 5(a):

(1) Employee shall not assist or directly or indirectly provide services, whether as a partner, employee, consultant, officer, director, manager, agent, associate, investor, or otherwise, to any person or entity which is at the time of such assistance or provision a “Competitor” of the Company. For purposes of this Section 5, the term “Competitor” means any person or entity that is engaged in the exploration and production of oil, gas or other hydrocarbons, the transportation thereof, any other midstream activities or the provision of oilfield services in any state or county/parish thereof in which the Company conducts business and/or has established business plans to conduct business activities within the twelve month period preceding Employee’s termination.

(2) In order to assist Employee with his or her duties, the Company shall continue to provide the Employee with access to confidential and proprietary information and other confidential information which is either information not known by actual or potential competitors, customers and third parties of the Company or is proprietary information of the Company (“Confidential Information”). Such Confidential Information shall include all non-public information the Employee acquired as a result of his or her positions with the Company that might be of any value to a competitor of the Company. Examples of such Confidential Information include, without limitation, non-public information about the Company’s customers, suppliers, and potential acquisition targets; its business operations, structure and methods of operation; its services and pricing; its processes, machines and inventions; it research and know-how; its business planning and strategies; information maintained in its computer systems; devices, processes, compilations of information and records; and future business plans. Employee agrees that such Confidential Information remains confidential even if committed to the Employee’s memory. Employee agrees not to use, divulge, or furnish or make accessible to any third party, company, corporation or other organization (including but not limited to customers, competitors, or governmental agencies), without the Company’s prior written consent, any Confidential Information of the Company, except as necessary in performing his or her duties on behalf of the Company during his or her employment with the Company. The Employee’s obligations under this Section will not apply to the extent that (i) the disclosure of Confidential Information is required by applicable law; provided that, prior to disclosing such Confidential Information, to the fullest extent practicable Employee must notify the Company thereof, which notice will include the basis upon which Employee believes the information is required to be disclosed, or (ii) information otherwise determined to be Confidential Information is or becomes generally available to the public or to persons generally knowledgeable in the Company’s industry without violation of this Agreement by Employee.

Company provided to Employee by the Company during the course of Employee’s employment with the Company will be returned to the Company immediately, with no request being required; and (ii) all Company computer and computer-related equipment and software, and all Company property, files, records, documents, drawings, specifications, lists, equipment and similar items relating to the business of the Company, whether prepared by the Employee or otherwise, coming into the Employee’s possession or control during the course of his or her employment shall remain the exclusive property of the Company, and shall be delivered by the Employee to the Company immediately, with no request being required.

(b) Employee specifically recognizes and affirms that each of the covenants contained in Section 5(a)(1) through (3) of this Agreement is a material and important term of this Agreement which has induced the Company to provide for the award of Performance Shares granted hereunder, the disclosure of the Confidential Information referenced herein, and the other promises made by the Company herein, and the Employee further agrees that in the event that he or she retires and thereafter (A) the Company determines that Employee has breached any term of Section 5(a) (1) through (3) or (B) all or any part of Section 5(a) is held or found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction in any action between the Employee and the Company, in addition to any other remedies at law or in equity the Company may have available to it, the Employee shall lose the right to receive Performance Shares and any unvested Performance Shares shall be deemed forfeited effective as of the date (A) the Company determines that Employee has breached any term of Section 5(a) or (B) all or any part of Section 5(a) is held or found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction in an action between the Employee and the Company.

(c) The Employee and the Company agree that the restrictions set forth in Section 5(a) are reasonable, including the geographic area, duration as to time, and scope of activities restrained. The Employee further agrees that if any covenant contained in Section 5(a) is found by a court of competent jurisdiction to contain limitations as to time, geographical area, or scope of activity that are not reasonable and impose a greater restraint than is necessary to protect the goodwill or other business interest of the Company, then the court shall reform the covenant to the extent necessary to cause the limitations contained in the covenant as to time, geographical area, and scope of activity to be restrained to be reasonable and to impose a restraint that is not greater than necessary to protect the goodwill and other business interests of the Company and to enforce the covenants as reformed.

(d) The covenants on the part of Employee in this Section 5 are considered independent of any other agreement, and the fact that the Employee has a claim against the Company, whether predicated upon this Agreement or otherwise, is not a defense to enforcement of this Section 5.

6. Upon either of a Change in Control (as defined below) or the Company’s ceasing to have publicly traded Common Stock as a result of a business combination or other extraordinary transaction, in each case prior to the completion of the Performance Period, the Performance Period shall be deemed complete and the Employee shall have earned 100% of the Performance Shares. If the Company ceases to have publicly traded Common Stock, then instead of any share of Common Stock that would otherwise be issued there shall instead be paid an amount of cash equal to the value of the consideration received by the shareholder of the Company in respect of a share of Common Stock in connection with the Change in Control or business combination or other extraordinary transaction.

“ Change in Control ” shall mean:

Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the entity resulting from such Business Combination (including, without limitation, an entity that as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (excluding any entity resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting from such Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common equity of the entity resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such entity except to the extent that such ownership existed prior to the Business Combination and (3) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non-corporate entity, resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

7. This Agreement is not an employment agreement. Nothing contained herein shall be construed as creating any employment relationship other than one at will.

8. This Agreement shall inure to the benefit of and be binding upon the heirs, legatees, distributees, executors and administrators of the Employee and the successors and assigns of the Company. In no event shall Performance Shares granted hereunder be voluntarily or involuntarily sold, pledged, assigned or transferred by the Employee other than by will or the laws of descent and distribution or pursuant to a qualified domestic relations order.

9. This Agreement shall be governed by the laws of the State of Delaware, without giving effect to conflict of law rules or principles. Any action or proceeding seeking to enforce any provision of or based on any right arising out of this Agreement may be brought against the Employee or the Company only in the courts of the State of Delaware or, if it has or can acquire jurisdiction, in the United States District Court for the District of Delaware, and the Employee and the Company consent to the jurisdiction of such courts (and of the appropriate appellate courts) in any action or proceeding and waives any objection to venue laid herein.

10. Employee agrees that as a condition to the award of the Performance Shares hereby, that Employee shall pay to the Company at the time or times requested by the Company, an amount of cash or shares of Common Stock equal to the amount the Company is required by any governmental authority to withhold for tax purposes with respect to any payment of earned Performance Shares, unless the Employee makes other prior arrangements for such withholding as may be approved by the Company.

11. The Employee shall have no rights of a shareholder with respect to the shares of Common Stock potentially deliverable pursuant to this Agreement unless and until such time as the ownership of such shares of Common Stock has been transferred to the Employee.

IN WITNESS WHEREOF, the parties hereto cause this Agreement to be executed as of the date hereof.

	CABOT OIL & GAS CORPORATION


	/s/ Scott C. Schroeder
	By:	Scott C. Schroeder
	Title:	Vice President, Chief Financial Officer
		& Treasurer


	[ Participant Name ]
	By:	Employee

Exhibit 10.7(d)

CABOT OIL & GAS CORPORATION

HYBRID PERFORMANCE SHARE AWARD AGREEMENT

This Hybrid Performance Share Award Agreement (the “Agreement”), made and entered into by and between Cabot Oil & Gas Corporation (the “Company”) with its principal office at 840 Gessner Road, Suite 1400, Houston, Texas 77024 and [ Participant Name ], (the “Employee”), is dated as of [ February 16, 2012 ].

1. Award. As an additional incentive and inducement to the Employee to remain in the employment of the Company, and to devote his or her best efforts to the business and affairs of the Company, the Company hereby awards to the Employee a Hybrid Performance Share Award of [ number of shares granted ] shares of Cabot Oil & Gas Corporation Common Stock, par value $.10 per share, (the “Hybrid Performance Shares”) upon the terms and conditions hereinafter set forth. The date of such grant is [ February 16, 2012 ] (“Date of Grant”).

2. Terms of Award. Subject to the terms and provisions of this Agreement, the restrictions on the Hybrid Performance Shares shall lapse (i) with respect to 33 1/3% of the total number of shares, as of the first anniversary of the Date of Grant; and (ii) with respect to an additional 33 1/3% of the total number of shares as of the second anniversary of the Date of Grant; and (iii) with respect to the remaining 33 1/3% of the total number of shares as of the third anniversary of the Date of Grant (each such date a “Date of Lapse of Restrictions”), provided that with respect to each 33 1/3% portion, such restrictions shall lapse only if the Company shall have $100 million or more of operating cash flow in the fiscal year immediately preceding such vesting date and only when the Committee has made a determination that such result was achieved, as provided below in Section 3. If the Company does not have $100 million or more of operating cash flow in the fiscal year immediately preceding a vesting date, the 33 1/3% of the Hybrid Performance Shares that would have vested on such date will be forfeited.

3. Certification. No later than the fifteenth business day following each Date of Lapse of Restrictions, the Committee shall determine, in writing, the extent to which the performance criteria have been met and the amount to be distributed with respect to the Hybrid Performance Shares as provided in Section 2 hereof and the Company shall issue to the Employee the appropriate number of shares of Common Stock. The Committee has sole and absolute authority and discretion to determine the amount to be distributed with respect to the Hybrid Performance Shares. The determination of the Committee shall be binding and conclusive on the Employee. Notwithstanding anything in this Agreement to the contrary, the Employee shall not be entitled to any Common Stock with respect to the Hybrid Performance Shares unless and until the Committee determines and certifies the extent to which the performance criteria have been met.

4. Termination of Employment. Except as otherwise provided in this Section 4, Section 5 or Section 6, in the event the Employee’s employment is terminated prior to the Date

of Lapse of Restrictions, all then-unvested Hybrid Performance Shares shall immediately be forfeited by the Employee. In the case of the termination of employment by reason of death, disability, or retirement, (under an approved retirement plan) all Hybrid Performance Shares shall, to the extent not previously vested, continue to vest on the original schedule with the level of payout, if at all, dependent on performance in accordance with this Agreement. Notwithstanding the foregoing and in the case of a retirement, an Employee must be an employee of the Company on September 30 th of the year the award is granted in order to continue vesting in the award. Further, a Participant must be an active employee of the Company at the time the Compensation Committee of the Board of Directors certifies the results of the Hybrid Performance Shares for employment termination other than death, disability or retirement. In the case of the termination of employment for any other reason, the Compensation Committee may, in its sole discretion, accelerate the vesting of some or all unvested Hybrid Performance Shares, upon such terms as the Compensation Committee deems advisable.

5. Confidential Information and Non-Competition. In consideration of (i) the Company disclosing and providing access to Confidential Information, as more fully described in Section 5(a) below, (ii) the grant by the Company of the Hybrid Performance Shares to provide an economic incentive to Employee to use Employee’s best efforts during his/her employment with the Company to advance the business and goodwill of the Company and in order to protect the Company’s interests in its Confidential Information and goodwill after the date hereof, and (iii) other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Employee, intending to be legally bound, hereby agrees as follows:

known by actual or potential competitors, customers and third parties of the Company or is proprietary information of the Company (“Confidential Information”). Such Confidential Information shall include all non-public information the Employee acquired as a result of his or her positions with the Company that might be of any value to a competitor of the Company. Examples of such Confidential Information include, without limitation, non-public information about the Company’s customers, suppliers, and potential acquisition targets; its business operations, structure and methods of operation; its services and pricing; its processes, machines and inventions; it research and know-how; its business planning and strategies; information maintained in its computer systems; devices, processes, compilations of information and records; and future business plans. Employee agrees that such Confidential Information remains confidential even if committed to the Employee’s memory. Employee agrees not to use, divulge, or furnish or make accessible to any third party, company, corporation or other organization (including but not limited to customers, competitors, or governmental agencies), without the Company’s prior written consent, any Confidential Information of the Company, except as necessary in performing his or her duties on behalf of the Company during his or her employment with the Company. The Employee’s obligations under this Section will not apply to the extent that (i) the disclosure of Confidential Information is required by applicable law; provided that, prior to disclosing such Confidential Information, to the fullest extent practicable Employee must notify the Company thereof, which notice will include the basis upon which Employee believes the information is required to be disclosed, or (ii) information otherwise determined to be Confidential Information is or becomes generally available to the public or to persons generally knowledgeable in the Company’s industry without violation of this Agreement by Employee.

(3) Employee agrees that whenever the Employee’s employment with the Company ends for any reason, (i) all documents containing or referring to the Company’s Confidential Information as may be in the Employee’s possession, or over which the Employee may have control, and all other property of the Company provided to Employee by the Company during the course of Employee’s employment with the Company will be returned to the Company immediately, with no request being required; and (ii) all Company computer and computer-related equipment and software, and all Company property, files, records, documents, drawings, specifications, lists, equipment and similar items relating to the business of the Company, whether prepared by the Employee or otherwise, coming into the Employee’s possession or control during the course of his or her employment shall remain the exclusive property of the Company, and shall be delivered by the Employee to the Company immediately, with no request being required.

Information referenced herein, and the other promises made by the Company herein, and the Employee further agrees that in the event that he or she retires and thereafter (A) the Company determines that Employee has breached any term of Section 5(a) (1) through (3) or (B) all or any part of Section 5(a) is held or found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction in any action between the Employee and the Company, in addition to any other remedies at law or in equity the Company may have available to it, the Employee shall lose the right to receive Hybrid Performance Shares and any unvested Hybrid Performance Shares shall be deemed forfeited effective as of the date (A) the Company determines that Employee has breached any term of Section 5(a) or (B) all or any part of Section 5(a) is held or found invalid or unenforceable for any reason whatsoever by a court of competent jurisdiction in an action between the Employee and the Company.

6. Change in Control . In the event of a Change in Control (as herein defined), any restriction periods and restrictions imposed on the Hybrid Performance Shares subject to this Agreement shall lapse, and on the fifteenth business day after the occurrence of a Change in Control (as herein defined), the stock certificates representing the Hybrid Performance Shares not previously delivered, without any restrictions or legend thereon, shall be delivered to the Employee.

“Change in Control” shall mean:

subsection (I), the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly from the Company, (ii) any acquisition by the Company, (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any entity controlled by the Company or (iv) any acquisition by any entity pursuant to a transaction which complies with clauses (1), (2) and (3) of subsection (III) of this definition; or

(III) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company (a “Business Combination”), in each case, unless, following such Business Combination, (1) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the entity resulting from such Business Combination (including, without limitation, an entity that as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (excluding any entity resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting from such Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common equity of the entity resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such entity except to the extent that such ownership existed prior to the Business Combination and (3) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non-corporate entity, resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

Notwithstanding the foregoing, none of the events described in subsections (I) through (IV) above shall constitute a Change in Control unless such event also meets the requirements of Section 409A(a)(2)(A)(v) of the Internal Revenue Code of 1986, as amended (the “Code”) and the related regulations and guidance.

7. Employment. This Agreement is not an employment agreement. Nothing contained herein shall be construed as creating any employment relationship other than one at will.

8. Assignment. This Agreement shall inure to the benefit of and be binding upon the heirs, legatees, distributees, executors and administrators of the Employee and the successors and assigns of the Company. In no event shall Hybrid Performance Shares granted hereunder be voluntarily or involuntarily sold, pledged, assigned or transferred by the Employee other than by will or the laws of descent and distribution or pursuant to a qualified domestic relations order.

9. Governing Law. This Agreement shall be governed by the laws of the State of Delaware, without giving effect to conflict of law rules or principles. Any action or proceeding seeking to enforce any provision of or based on any right arising out of this Agreement may be brought against the Employee or the Company only in the courts of the State of Delaware or, if it has or can acquire jurisdiction, in the United States District Court for the District of Delaware, and the Employee and the Company consent to the jurisdiction of such courts (and of the appropriate appellate courts) in any action or proceeding and waives any objection to venue laid herein.

10. Taxes. Employee agrees that as a condition to the award of the Hybrid Performance Shares hereby, that Employee shall pay to the Company at the time or times requested by the Company, an amount of cash or shares of Common Stock equal to the amount the Company is required by any governmental authority to withhold for tax purposes with respect to any payment of earned Hybrid Performance Shares, unless the Employee makes other prior arrangements for such withholding as may be approved by the Company.

11. Shareholder Status. The Employee shall have no rights of a shareholder with respect to the shares of Common Stock potentially deliverable pursuant to this Agreement unless and until such time as the ownership of such shares of Common Stock has been transferred to the Employee.

12. Controlling Agreement. This Agreement shall supersede and control over any other agreement between the Company and the Employee, whether entered previously or entered subsequent to the date hereof, related to Hybrid Performance Shares awarded hereunder.

13. Recapitalization . In the event of any merger, reorganization, consolidation, recapitalization, stock split, separation, liquidation, stock dividend, split-up, share combination, or other change in the corporate structure of the Company affecting the Hybrid Performance Shares, the number of Hybrid Performance Shares subject to this Agreement shall be equitably adjusted by the Compensation Committee to prevent dilution or enlargement of rights.

14. Miscellaneous .

(a) This Agreement shall not confer upon the Employee any right to continuation of employment by the Company; nor shall this Agreement interfere in any way with the Company’s right to terminate his or her employment at any time.

(c) This Agreement shall be subject to all applicable laws, rules and regulations, and to such approvals by any governmental agencies or national securities exchanges as may be required.

15. Section 409A Compliance .

The following provisions shall apply to this Agreement, notwithstanding any provision to the contrary:

(b) This Agreement shall not be amended in a manner that would cause the Agreement or any amounts payable under the Agreement to fail to comply with the requirements of Section 409A, to the extent applicable, and, further, the provisions of any purported amendment that may reasonably be expected to result in such non-compliance shall be of no force or effect with respect to the Agreement.

(e) For purposes of Section 409A, each payment under this Agreement shall be deemed to be a separate payment.

(f) Notwithstanding any provision of this Plan to the contrary, if the Employee is a “specified employee” within the meaning of Section 409A as of the date of the termination of the Employee’s employment, then any amounts or benefits which

(i) are payable under this Agreement upon the upon the Employee’s “separation from service” within the meaning of Section 409A,

(ii) are subject to the provisions of Section 409A,

(iii) are not otherwise excluded under Section 409A, and

(iv) would otherwise be payable during the first six-month period following such separation from service

shall be paid on the fifteenth business day next following the earlier of (i) the expiration of six months from the date of the termination of the Employee’s employment or (ii) the date of the Employee’s death.

IN WITNESS WHEREOF, the parties hereto cause this Agreement to be executed as of the date hereof.

	Company:

	CABOT OIL & GAS CORPORATION


	/s/ Scott C. Schroeder
	By:	Scott C. Schroeder
	Title:	Vice President, Chief Financial Officer
		& Treasurer


	Employee:



	[ Participant Name ]

Exhibit 10.7(e)

CABOT OIL & GAS CORPORATION
PERFORMANCE SHARE AWARD AGREEMENT

This Performance Award Agreement (the “Agreement”), made and entered into by and between Cabot Oil & Gas Corporation (the “Company”) with its principal office at 840 Gessner Road, Suite 1400, Houston, Texas 77024 and [ Participant Name ], (the “Employee”), is dated as of [ February 16, 2012 ].

As an additional incentive and inducement to the Employee to remain in the employment of the Company, and to devote his or her best efforts to the business and affairs of the Company, the Company hereby awards to the Employee a Performance Award of [ number of shares granted ] performance shares (the “Performance Shares”) upon the terms and conditions hereinafter set forth.

1. The performance period for the Performance Shares subject to this Agreement shall be the period beginning January 1, 2012 and ending December 31, 2014 (the “Performance Period”).

2. Each Performance Share represents the right to receive, after the end of the Performance Period and based on the Company’s performance, the aggregate of from 0 to 100% of the Fair Market Value of a share of Common Stock payable in Common Stock plus from 0 to 100% of the Fair Market Value of a share of Common Stock in cash. The number of shares of Common Stock and cash to be issued or paid shall be determined based on the relevant criteria and Common Stock Fair Market Value as of the end of the Performance Period. Each Performance Share shall be payable first in Common Stock of the Company and to the extent that the percentage of a Performance Share earned at the end of the Performance Period exceeds 100%, such Performance Share percentage shall be paid in cash. Cash will also be paid in lieu of the issuance of fractional shares of Common Stock. The determination of the amount to be distributed with respect to a Performance Share at the end of the Performance Period shall be based upon the Company’s achievement of performance criteria established by the Committee for the Performance Period as set forth below (the “Performance Criteria”).

The Performance Criteria that determines the number of shares of Common Stock (and cash) of the Company issued per Performance Share is the relative Total Shareholder Return (as defined below) on the Company’s Common Stock as compared to the Total Shareholder Return on the common equity of each company in the Comparator Group (as defined below). “Total Shareholder Return” shall be expressed as a percentage equal to common stock price appreciation as averaged from the first and last month of the Performance Period plus dividends (on a cumulative reinvested basis). The “Comparator Group” is the group of companies set forth on Exhibit A hereto and which will be used for comparison purposes in determining if the Performance Criteria have been met. If any member of the Comparator Group ceases to have

publicly traded common stock, the Committee may select a replacement company which shall be included in the Comparator Group as of January 1, 2012 instead of the replaced member.

After the end of the Performance Period, the shares of Common Stock and cash earned with respect to each Performance Share for such period shall be determined based on the relative ranking of the Company versus the Comparator Group for Total Shareholder Return during the Performance Period using the following scale:

Company Relative Placement	Percent Performance Shares		Value Consideration
1-2 (highest)	200	%	100% stock / 100% cash
3	185	%	100% stock / 85% cash
4	170	%	100% stock / 70% cash
5	155	%	100% stock / 55% cash
6	140	%	100% stock / 40% cash
7	125	%	100% stock / 25% cash
8	110	%	100% stock / 10% cash
9	100	%	Stock
10	90	%	Stock
11	75	%	Stock
12	60	%	Stock
13	45	%	Stock
14	30	%	Stock
15	15	%	Stock
16-17 (lowest)	0

3. No later than the fifteenth business day following the close of the Performance Period, the Committee shall determine, in writing, the extent to which the Performance Criteria have been met and the amount to be distributed with respect to a Performance Share as provided in Section 2 hereof and the Company shall issue or pay to the Employee the appropriate number of shares of Common Stock and cash. The Committee has sole and absolute authority and discretion to determine the amount to be distributed with respect to Performance Shares. The determination of the Committee shall be binding and conclusive on the Employee. Notwithstanding anything in this Agreement to the contrary, the Employee shall not be entitled to any Common Stock or cash with respect to the Performance Shares unless and until the Committee determines and certifies the extent to which the Performance Criteria have been met.

4. Except as otherwise provided in this Section 4, Section 5 or Section 6, in the event the Employee’s employment is terminated for any reason prior to the completion of the Performance Period, the Performance Shares shall be immediately forfeited unless otherwise determined by the Committee. In the case of the termination of employment by reason of death, disability, or retirement (under an approved retirement plan), the Performance Shares shall not be so forfeited and shall otherwise be payable as set forth herein as if such employment continued through the end of the Performance Period. Notwithstanding the foregoing and in the case of a retirement, a Participant must be an employee of the Company on September 30 th of the year the Performance Shares are granted in order to continue vesting in the Performance Shares. Further, a Participant must be an active employee of the Company at the time the

Compensation Committee of the Board of Directors certifies the results of the performance shares for employment termination other than death, disability or retirement.

even if committed to the Employee’s memory. Employee agrees not to use, divulge, or furnish or make accessible to any third party, company, corporation or other organization (including but not limited to customers, competitors, or governmental agencies), without the Company’s prior written consent, any Confidential Information of the Company, except as necessary in performing his or her duties on behalf of the Company during his or her employment with the Company. The Employee’s obligations under this Section will not apply to the extent that (i) the disclosure of Confidential Information is required by applicable law; provided that, prior to disclosing such Confidential Information, to the fullest extent practicable Employee must notify the Company thereof, which notice will include the basis upon which Employee believes the information is required to be disclosed, or (ii) information otherwise determined to be Confidential Information is or becomes generally available to the public or to persons generally knowledgeable in the Company’s industry without violation of this Agreement by Employee.

6. Upon either of a Change in Control (as defined below) or the Company’s ceasing to have publicly traded Common Stock as a result of a business combination or other extraordinary transaction (either to be known as a “Corporate Event”), in each case prior to the completion of the Performance Period, the Performance Period shall be deemed complete and the Employee shall have earned the Performance Shares as calculated in Section 2 above based on Company Relative Placement as of the last day of the month prior to the month in which the Corporate Event occurred, without any proration by reason of the shortened Performance Period.

Total Shareholder Return at termination of the Performance Period shall be the greater of (i) the result determined under Section 2 above or (ii) the result determined under Section 2 above substituting for the Company average stock price for the last month of the Performance Period the value of consideration per share of such Common Stock received by a shareholder of the Company in connection with the Corporate Event (the “Deemed Share Value”).

If the Corporate Event also meets the requirements of Section 409A(a)(2)(A)(v) of the Internal Revenue Code of 1986, as amended and the related regulations and guidance (collectively, “Section 409A”), then the shares of Common Stock and cash earned (if any) shall be issued to the Employee as provided in Section 3, except that if the Company ceases to have publicly traded Common Stock, then, instead of any share of Common Stock that would otherwise be issued, there shall instead be paid a single lump-sum payment of cash in the amount equal to the aggregate of the Deemed Share Value for each full and fractional share to which the Employee is entitled.

In all other cases, any benefits to which the Employee becomes entitled by operation of this Section 6 shall be payable (i) on the date on which payment would otherwise have been made had the Performance Period ended as originally scheduled pursuant to Section 1 and (ii) in the form of a single lump-sum payment. Unless the Compensation Committee directs otherwise in advance of the Corporate Event, the payment shall be made in cash and shall be in an amount

equal to the sum of (1) the aggregate of the Deemed Share Value on the date of the Corporate Event for each full and fractional share to which the Employee is entitled, plus (2) interest compounded monthly from the date of the Corporate Event to the date of payment at the prime interest rate set forth in the Wall Street Journal (or, if such publication ceases to exist, a published interest rate from a source approved by the Compensation Committee, in its sole discretion), as adjusted from time to time.

“Change in Control” shall mean:

same proportions as their ownership, immediately prior to such Business Combination, of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (2) no Person (excluding any entity resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting from such Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common equity of the entity resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such entity except to the extent that such ownership existed prior to the Business Combination and (3) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non-corporate entity, resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

7. This Agreement is not an employment agreement. Nothing contained herein shall be construed as creating any employment relationship other than one at will.

12. This Agreement shall supersede and control over any other agreement between the Company and the Employee, whether entered previously or entered subsequent to the date hereof, related to Performance Shares awarded hereunder.

13. The following provisions shall apply to this Agreement, notwithstanding any provision to the contrary:

(I) This Agreement is intended to comply with Section 409A and ambiguous provisions, if any, shall be construed in a manner that is compliant with or exempt from the application of Section 409A.

(II) This Agreement shall not be amended in a manner that would cause the Agreement or any amounts payable under the Agreement to fail to comply with the requirements of Section 409A, to the extent applicable, and, further, the provisions of any purported amendment that may reasonably be expected to result in such non-compliance shall be of no force or effect with respect to the Agreement.

(III) The Company shall neither cause nor permit any payment, benefit or consideration to be substituted for a benefit that is payable under this Agreement if such action would result in the failure of any amount that is subject to Section 409A to comply with the applicable requirements of Section 409A.

(IV) The Company shall neither cause nor permit any adjustments to any equity interest to be made in a manner that would result in the equity interest’s becoming subject to Section 409A unless, after such adjustment, the equity interest is in compliance with the requirements of Section 409A to the extent applicable.

(V) For purposes of Section 409A, each payment under this Agreement shall be deemed to be a separate payment.

(VI) Notwithstanding any provision of this Plan to the contrary, if the Employee is a specified employee as of the date of the termination of the Employee’s employment, then any amounts or benefits which

(1) are payable under this Agreement upon the upon the Employee’s “separation from service” within the meaning of Section 409A,

(2) are subject to the provisions of Section 409A,

(3) are not otherwise excluded under Section 409A, and

(4) would otherwise be payable during the first six-month period following such separation from service

IN WITNESS WHEREOF, the parties hereto cause this Agreement to be executed as of the date hereof.

	CABOT OIL & GAS CORPORATION


	/s/ Scott C. Schroeder
	By:	Scott C. Schroeder
	Title:	Vice President, Chief Financial Officer
		& Treasurer


	Employee:


	[ Participant Name ]

EXHIBIT A
COMPARATOR GROUP

BERRY PETROLEUM COMPANY

CIMAREX ENERGY COMPANY

CONCHO RESOURCES INC.

EQT CORPORATION

EXCO RESOURCES INC.

NEWFIELD EXPLORATION COMPANY

NOBLE ENERGY INC.

PIONEER NATIONAL RESOURCES COMPANY

PLAINS EXPLORATION & PRODUCTION COMPANY

QEP RESOURCES INC.

QUICKSILVER RESOURCES, INC.

RANGE RESOURCES CORPORATION

SOUTHWESTERN ENERGY COMPANY

SM ENERGY COMPANY

ULTRA PETROLEUM

WPX ENERGY, INC.

Exhibit 10.9

CABOT OIL & GAS CORPORATION SAVINGS INVESTMENT PLAN

(As Amended and Restated Effective January 1, 2009)

Third Amendment

WHEREAS, effective January 1, 1991, Cabot Oil & Gas Corporation (the “Company”) established the Cabot Oil & Gas Corporation Savings Investment Plan and has amended and restated the Plan on several occasions since that date, most recently as of January 1, 2009 (the “Plan”); and

WHEREAS, the Company desires to amend the Plan to eliminate any reference to the Cabot Oil & Gas Corporation Pension Plan, which has been terminated;

NOW, THEREFORE, having reserved the right to amend the Plan pursuant to Section 10.4 thereof, the Company hereby amends the Plan, effective as of January 1, 2012, as follows:

Section 1.42 of the Plan is hereby amended, in its entirety, to read as follows:

“1.42 Retirement Date : The first day of the month following a Member’s termination of Service on or after his sixty-fifth (65th) birthday or, if earlier, the first day of the month following a Member’s termination of Service after he has completed at least ten (10) years of Vesting Service and has attained age fifty-five (55). Effective as of , 2012, for any Member who, as of such date, has not attained age 65 and does not have at least three (3) years of Vesting Service, a Member shall not be considered to have reached his or her Retirement Date until such Member has completed at least five (5) years of Vesting Service.

IN WITNESS WHEREOF, the Company, acting by and through its duly authorized officer, has caused this Amendment to be executed as of the day of , 2012, to become effective as of the dates set forth above.

	CABOT OIL & GAS CORPORATION

	By:

	Title:

Exhibit 10.10

CABOT OIL & GAS CORPORATION
NONEMPLOYEE DIRECTOR DEFERRED COMPENSATION PLAN

(As Established Effective December 21, 2012)

1. COVERAGE OF PLAN

This Nonemployee Director Deferred Compensation Plan is maintained by Cabot Oil & Gas Corporation, a Delaware corporation, as a sub-plan of the Cabot Oil & Gas Corporation 2004 Incentive Plan for the purpose of providing its nonemployee directors the opportunity to defer the receipt of cash compensation otherwise payable to such directors in accordance with the terms set forth herein.

2. DEFINITIONS

2.1. “ Annual Fees ” means the annual cash retainer earned by a Participant during a Plan Year, including in cash payments for serving as a Board committee chair or lead outside director.

2.2. “ Board ” means the Board of Directors of the Company.

2.3. “ Code ” means the Internal Revenue Code of 1986, as amended.

2.4. “ Committee ” means the Board or, if the Board so determines, a committee appointed by the Board to administer the Plan.

2.5. “ Common Stock ” has the meaning set forth in the Incentive Plan.

2.6. “ Company ” means Cabot Oil & Gas Corporation, a Delaware corporation, including any successor thereto by merger, consolidation, acquisition of all or substantially all the assets thereof, or otherwise.

2.7. “ Election ” means a written election on a form provided by the Company, filed with the Company in accordance with Article 3, pursuant to which an Eligible Director may elect to 25%, 50%, 75% or 100% of the Eligible Director’s Annual Fees and instead receive Restricted Stock Units under the Incentive Plan whose grant date value is equal to the amount of Annual Fees which the Participant would otherwise have received had no Election been made.

2.8. “ Eligible Director ” means the members of the Board who are not employees of the Company or any of its subsidiaries.

2.9. “ Fair Market Value ” has the meaning set forth in the Incentive Plan.

2.10. “ Fee Payment Date ” means any date as of which a Participant’s Annual Fees deferred pursuant to this Plan would have otherwise been paid. Annual Fees shall be paid quarterly in arrears for the preceding quarter on January 15, April 15, July 15 and October 15 of each year.

2.11. “ Incentive Plan ” means the Cabot Oil & Gas Corporation 2004 Incentive Plan, as amended, and any successor plan.

2.12. “ New Eligible Director ” means a member of the Board who, during any Plan Year, first becomes an Eligible Director.

2.13. “ Participant ” means each Eligible Director who has made an Election.

2.14. “ Plan ” means the Cabot Oil & Gas Corporation Nonemployee Director Deferred Compensation Plan, as set forth herein, and as may be amended from time to time.

2.15. “ Plan Year ” means the calendar year.

2.16. “ Restricted Stock Unit Agreement ” means the Award Agreement (as defined in the Incentive Plan) governing the grant of Restricted Stock Units, a form of which is attached as Exhibit A.

2.17. “ Restricted Stock Unit ” has the meaning set forth in the Incentive Plan.

2.18. “ Section 409A ” means section 409A of the Code and any Treasury Regulations promulgated under, or other administrative guidance issued with respect to, such Code section, as applicable to the Plan at the relevant time.

3. ELECTIONS TO DEFER ANNUAL FEES

3.1. Elections . An Election shall be made on the form acceptable to the Committee for the purpose of deferring Annual Fees. Each Eligible Director, by filing an Election at the time and in the form described in this Article 3, shall have the right to defer all or any portion of the Annual Fees that he or she otherwise would be entitled to receive and instead receive a grant of Restricted Stock Units under the Incentive Plan as of the applicable Fee Payment Date. To the extent any Annual Fees are deferred, the Participant will receive as of the applicable Fee Payment Date a number of Restricted Stock Units equal to the amount of Annual Fees deferred that would have been paid on such Fee Payment Date divided by the Fair Market Value per share of Common Stock on the Fee Payment Date; provided, however, that no fractional Restricted Stock Units shall be granted. The Annual Fees of such Eligible Director for a Plan Year shall be reduced in an amount equal to the portion of such compensation deferred by such Eligible Director for the Plan Year pursuant to the Eligible Director’s Election. Such reduction shall be effected by reducing the quarterly payment of Annual Fees by the percentage specified in the Election. Any Restricted Stock Units received by a Participant pursuant to an Election under this Article 3 shall be governed by and subject to the terms and conditions of the Restricted Stock Unit Agreement and the Incentive Plan.

3.2. Filing of Election . Except as provided in Section 3.3, no Election shall be effective with respect to Annual Fees unless it is filed with the Company on or before the close of business on December 31 of the Plan Year preceding the Plan Year to which the Election applies. An Election described in the preceding sentence shall become irrevocable on December 31 of the Plan Year preceding the Plan Year to which the Election applies.

3.3. Filing of Election by New Eligible Directors . Notwithstanding Section 3.2, a New Eligible Director may elect to defer all or any portion of his or her Annual Fees earned for the performance of services in the Plan Year in which the New Eligible Director becomes a New Eligible Director, beginning with the next following payment of any Annual Fees after the filing of an Election with the Company and before the close of such Plan Year by making and filing the Election with the Company within 30 days of the date on which such New Eligible Director becomes a New Eligible Director. Any Election by such New Eligible Director for succeeding Plan Years shall be made in accordance with Section 3.2.

3.4. Plan Years to which Election May Apply . A separate Election may be made for each Plan Year as to which an Eligible Director desires to defer all or any portion of such Eligible Director’s Annual Fees, or an Eligible Director may make an Election with respect to a Plan Year that will remain in effect for subsequent Plan Years unless the Eligible Director revokes such Election or timely makes a new Election with respect to a subsequent Plan Year. Any revocation of an Election must be in writing and must be filed with the Company on or before December 31 of the Plan Year immediately preceding the Plan Year to which such revocation applies. The failure of an Eligible Director to make an Election for any Plan Year shall not affect such Eligible Director’s right to make an Election for any other Plan Year.

3.5. Distribution Event. Any Restricted Stock Units received by a Participant pursuant to an election by a Participant to defer all or any portion of such Participant’s Annual Fees shall be settled in accordance with the terms of the applicable Restricted Stock Unit Agreement on the date the Participant ceases to be a member of the Board.

4. AUTHORITY OF COMMITTEE

This Plan shall be administered by the Committee. The Committee shall have full and exclusive authority to construe, interpret and administer this Plan and take all actions and make all determinations on behalf of the Company unless otherwise indicated, and the Committee’s construction and interpretation thereof and determinations thereunder shall be binding and conclusive on all persons for all purposes. The Committee may delegate to the Chief Executive Officer and to other senior officers of the Company its duties under this Plan pursuant to such conditions or limitations as the Committee may establish. To the fullest extent permitted by applicable law, no member of the Committee or officer of the Company to whom the Committee has delegated authority in accordance with the provisions of this Plan shall be liable for anything done or omitted to be done by him or her, by any member of the Committee or by an officer of the Company in connection with the performance of any duties under this Plan.

5. AMENDMENT OR TERMINATION

The Company, by action of the Committee, reserves the right at any time, or from time to time, to amend or modify this Plan, including amendments for the purpose of complying with Section 409A. The Company, by action of the Committee, reserves the right at any time to terminate this Plan. Notwithstanding the foregoing, no amendment, modification or termination shall, without the consent of the Participant, impair the rights of any Participant to the number of Restricted Stock Units outstanding as of the date of such amendment, modification or termination.

6. MISCELLANEOUS PROVISIONS

6.1. No Right to Continued Service . Nothing contained herein shall be construed as conferring upon any Participant the right to remain in the service of the Company, its subsidiaries or divisions, in any capacity.

6.2. Expenses of Plan . All expenses of the Plan shall be paid by the Company.

6.3. Unfunded Plan . Nothing contained herein shall be deemed to create a trust of any kind or create any fiduciary relationship. This Plan shall be unfunded. To the extent that a Participant acquires a right to receive delivery of shares of Common Stock from the Company under the Plan, such right shall not be greater than the right of any unsecured general creditor of the Company and such right shall be an unsecured claim against the general assets of the Company. Although bookkeeping accounts may be established with respect to Participants, any such accounts shall be used merely as a bookkeeping convenience. The Company shall not be required to segregate any assets that may at any time be represented by Common Stock or rights thereto, nor shall this Plan be construed as providing for such segregation, nor shall the Company, the Board or the Committee be deemed to be a trustee of any stock or rights thereto to be granted under this Plan. Any liability or obligation of the Company to any Participant with respect to Common Stock or rights thereto under this Plan shall be based solely upon any contractual obligations that may be created by this Plan, and no such liability or obligation of the Company shall be deemed to be secured by any pledge or other encumbrance on any property of the Company. Neither the Company nor the Board nor the Committee shall be required to give any security or bond for the performance of any obligation that may be created by this Plan.

6.4. Gender and Number . Whenever any words are used herein in any specific gender, they shall be construed as though they were also used in any other applicable gender. The singular form, whenever used herein, shall mean or include the plural form, and vice versa, as the context may require.

6.5. Law Governing Construction . The construction and administration of the Plan and all questions pertaining thereto, shall be governed by the laws of the State of Texas.

6.6. Headings Not a Part Hereof . Any headings preceding the text of the several Articles, Sections, subsections, or paragraphs hereof are inserted solely for convenience of reference and shall not constitute a part of the Plan, nor shall they affect its meaning, construction, or effect.

6.7. Severability of Provisions . If any provision of this Plan is determined to be void by any court of competent jurisdiction, the Plan shall continue to operate and, for the purposes of the jurisdiction of that court only, shall be deemed not to include the provision determined to be void.

6.8. Compliance with Section 409A . This Plan is intended to comply in all respects with Section 409A and at all times shall be interpreted and operated in compliance therewith.

7. EFFECTIVE DATE

The effective date of this Plan shall be December 21, 2012.

IN WITNESS WHEREOF, Cabot Oil & Gas Corporation has caused this Plan to be executed by its duly authorized officer as of the 21 st day of December, 2012.

	CABOT OIL & GAS CORPORATION

	By:	/s/ Deidre L. Shearer
	Deidre L. Shearer
	Corporate Secretary and Managing Counsel

EXHIBIT A

Form of Restricted Stock Unit Agreement

A-1

Exhibit 21.1

SUBSIDIARIES OF CABOT OIL & GAS CORPORATION

Big Sandy Gas Company

Cabot Oil & Gas Marketing Corporation *

Cabot Pipeline Holdings LLC

Cody Energy LLC

Cody Oil & Gas, Inc.

Cranberry Pipeline Corporation *

Cabot Petroleum Canada Corporation

Cabot Oil & Gas Holdings Company

COG Finance Corporation

GasSearch Drilling Services Corporation

Cody Texas, L.P.

Susquehanna Real Estate I Corporation

* Denotes significant subsidiary.

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File Nos. 333-68350 and 333-83819) and Form S-8 (File Nos. 333-37632, 33-53723, 33-35476, 333-92264, 333-123166 and 333-135365) of Cabot Oil & Gas Corporation of our report dated February 28, 2013 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 28, 2013

Exhibit 23.2

January 31, 2013

Cabot Oil & Gas Corporation

Three Memorial City Plaza

840 Gessner

Suite 1400

Houston, TX 77024

	Re:	Securities and Exchange Commission
		Form 10-K of Cabot Oil & Gas Corporation

Gentlemen:

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-68350 and 333-83819) and Form S-8 (File Nos. 333-37632, 33-53723, 33-35476, 333-92264, 333-123166 and 333-135365) of Cabot Oil & Gas Corporation of our report dated January 31, 2013, regarding the Cabot Oil & Gas Corporation Proved Reserves and Future Net Revenues as of December 31, 2012, and of references to our firm which report and references are to be included in Form 10-K for the year ended December 31, 2012 to be filed by Cabot Oil & Gas Corporation with the Securities and Exchange Commission.

The Form 10-K contains references to certain reports prepared by Miller and Lents, Ltd. for the use of Cabot Oil & Gas Corporation. The analysis, conclusions, and methods contained in the reports are based upon information that was made available to us at the time the reports were prepared and Miller and Lents, Ltd. has not updated and undertakes no duty to update any results contained in the reports based on the aforementioned information. While the reports may be used as a descriptive resource, investors are advised that Miller and Lents, Ltd. has not verified information provided by others except as specifically noted in the reports, and Miller and Lents, Ltd. makes no representation or warranty as to the accuracy of such information. Moreover, the conclusions contained in such reports are based on assumptions that Miller and Lents, Ltd. believed were reasonable at the time of the preparation of the Reports and that are described in the Reports in reasonable detail. However, there is a wide range of uncertainties and risks subsequent to the preparation of the Reports that are outside our control that may impact these assumptions, including but not limited to, unforeseen market changes, economic changes, natural events, actions of governments or individuals, and changes in or the interpretation of laws and regulations.

Miller and Lents, Ltd. has no financial interest in Cabot Oil & Gas Corporation or in any of its affiliated companies or subsidiaries and is not to receive any such interest as payment for such report. Miller and Lents, Ltd. also has no director, officer, or employee employed or otherwise connected with Cabot Oil & Gas Corporation. We are not employed by Cabot Oil & Gas Corporation on a contingent basis.

	Yours very truly,

	MILLER AND LENTS, LTD.
	Texas Registered Engineering Firm No. F-1442


	/s/ Carl D. Richard, P.E
	Carl D. Richard, P.E.
	Senior Vice President

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Exhibit 31.1

I, Dan O. Dinges, certify that:

1. I have reviewed this annual report on Form 10-K of Cabot Oil & Gas Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal controls over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls over financial reporting.

Date: February 28, 2013


		/s/ DAN O. DINGES Dan O. Dinges Chairman, President and Chief Executive Officer

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Exhibit 31.1

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Exhibit 31.2

I, Scott C. Schroeder, certify that:

1. I have reviewed this annual report on Form 10-K of Cabot Oil & Gas Corporation;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls over financial reporting.

Date: February 28, 2013


		/s/ SCOTT C. SCHROEDER Scott C. Schroeder Vice President and Chief Financial Officer

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Exhibit 31.2

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Exhibit 32.1

Certification Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) (the "Act"), each of the undersigned, Dan O. Dinges, Chief Executive Officer of Cabot Oil & Gas Corporation, a Delaware corporation (the "Company"), and Scott C. Schroeder, Chief Financial Officer of the Company, hereby certify that, to his knowledge:

(1) the Company's Annual Report on Form 10-K for the year ended December 31, 2012 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


Dated: February 28, 2013		/s/ DAN O. DINGES Dan O. Dinges Chief Executive Officer
		/s/ SCOTT C. SCHROEDER Scott C. Schroeder Chief Financial Officer

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Exhibit 32.1

Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Exhibit 99.1

January 31, 2013

Cabot Oil & Gas Corporation

Three Memorial City Plaza Building

840 Gessner Road, Suite 1400

Houston, Texas 77024-4152

	Re:	Audit of
		Reserves and Future Net Revenues
		As of December 31, 2012
		SEC Price Case

Gentlemen:

At your request, Miller and Lents, Ltd. (MLL) performed an audit of the estimates of proved reserves of oil, and gas and the future net revenues associated with these reserves that Cabot Oil & Gas Corporation (Cabot) attributes to its net interests in oil and gas properties as of December 31, 2012. The audit report was prepared for the use of Cabot in its annual financial and reserves reporting and was completed on January 30, 2013. Cabot’s estimates, shown below, are in accordance with the definitions contained in Securities and Exchange Commission (SEC) Regulation S-X, Rule 4-10(a) as shown in the Appendix.

Reserves and Future Net Revenues as of December 31, 2012

	Net Reserves		Future Net Revenues
Reserves Category	Liquids, MBbls.	Gas, MMcf	Undiscounted, M$	Discounted at 10% Per Year, M$
Proved Developed	12,829	2,216,190	4,500,795	2,347,499
Proved Undeveloped	11,546	1,479,947	2,411,178	786,696
Total Proved	24,375	3,696,137	6,911,973	3,134,195

We prepared independent estimates of 100 percent of the proved reserves reported by Cabot. Based on our investigations and subject to the limitations described hereinafter, it is our judgment that (1) the reserves estimation methods employed by Cabot were appropriate, and its classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) its reserves estimation processes were comprehensive and of sufficient depth, (3) the data upon which Cabot relied were adequate and of sufficient quality, and (4) the results of those estimates and projections are, in the aggregate, reasonable.

Cabot’s reserves estimates were based on decline curve extrapolations, material balance calculations, volumetric calculations, analogies, or combinations of these methods for each well,

reservoir, or field. Reserves estimates from volumetric calculations and from analogies are often less certain than reserves estimates based on well performance obtained over a period during which a substantial portion of the reserves were produced.

All reserves discussed herein are located within the Continental United States and Canada. Gas volumes were estimated at the appropriate pressure base and temperature base that are established for each well or field by the applicable sales contract or regulatory body. Total gas reserves were obtained by summing the reserves for all the individual properties and are therefore stated herein at a mixed pressure base.

Cabot represents that the future net revenues reported herein were computed based on prices for oil and gas, utilizing the 12-month averages of the first-day-of-the-month prices, and are in accordance with SEC guidelines. Cabot used benchmark prices of $94.70 per barrel based on the West Texas Intermediate Spot Price at Cushing, Oklahoma and $2.76 per MMBtu based on the Henry Hub Spot Price for its reserves estimates. The average prices used in this report for proved reserves, after appropriate adjustments, were $96.43 per barrel for liquids and $2.83 per Mcf for gas. The present value of future net revenues was computed by discounting the future net revenues at 10 percent per year. Estimates of future net revenues and the present value of future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

In its estimates of proved reserves and future net revenues associated with its proved reserves, Cabot considered that a portion of its facilities associated with the movement of its gas in the Northern Region to its markets are unusual in that the construction and operation of these facilities are highly dependent on its producing operations. Cabot deemed the portion of the costs of these facilities associated with its revenue interest gas as costs attributable to its oil- and gas-producing activities and, accordingly, included these costs in its computation of the future net revenues associated with its proved reserves.

In making its projections, Cabot included cost estimates for well abandonment and well site reclamations. Cabot’s estimates include no adjustments for production prepayments, exchange agreements, gas balancing, or similar arrangements. We were provided with no information concerning these conditions, and we have made no investigations of these matters as such was beyond the scope of this investigation.

In conducting this evaluation, we relied upon, without independent verification, Cabot’s representation of (1) ownership interests, (2) production histories, (3) accounting and cost data, (4) geological, geophysical, and engineering data, and (5) development schedules. These data were accepted as represented and were considered appropriate for the purpose of the audit report. To a lesser extent, nonproprietary data existing in the files of Miller and Lents, Ltd., and data obtained from commercial services were used. We employed all methods, procedures, and assumptions considered necessary in utilizing the data provided to prepare the report.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments and are subject to the inherent uncertainties associated with interpretation of geological, geophysical, and engineering information. These uncertainties include, but

are not limited to, (1) the utilization of analogous or indirect data and (2) the application of professional judgments. Government policies and market conditions different from those employed in this study may cause (1) the total quantity of oil, natural gas liquids, or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. At this time, MLL is not aware of any regulations that would affect Cabot’s ability to recover the estimated reserves.

Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in Cabot. Our compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity. Production of this report was supervised by Carl D. Richard, P.E., an officer of the firm who is a licensed Professional Engineer in the State of Texas and is professionally qualified, with more than 25 years of relevant experience, in the estimation, assessment, and evaluation of oil and gas reserves.

If you have any questions regarding this evaluation, or if we can be of further assistance, please contact us.

	Very truly yours,

	MILLER AND LENTS, LTD.
	Texas Registered Engineering Firm No. F-1442


	By	/s/ James A. Cole
		James A. Cole, P.E.
		Senior Consultant


	By	/s/ Carl D. Richard
		Carl D. Richard, P.E.
		Senior Vice President

JAC/CDR/psh