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SEC Filings

10-K

CABOT OIL & GAS CORP filed this Form 10-K on 02/28/2013

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TABLE OF CONTENTS

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Table of Contents

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 endedDecember 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
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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 Item405 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

Form10-K or any amendment to this Form10-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):

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 BYREFERENCE

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.

Large accelerated filer ý Accelerated filer o Non-accelerated filer o

(Do not check if a

smaller reporting company)

Smaller reporting company o
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TABLEOF CONTENTS

PAGE

PART I

ITEMS 1 and2 Business and Properties

6

ITEM1A Risk Factors

21

ITEM1B Unresolved Staff Comments

33

ITEM3 Legal Proceedings

33

ITEM4 Mine Safety Disclosures

33

Executive Officers of the Registrant

34

PART II

ITEM5 Market for Registrant's Common Equity, Related Stockholder Matters

and Issuer Purchases of Equity Securities

35

ITEM6 Selected Financial Data

37

ITEM7 Management's Discussion and Analysis of Financial Condition and

Results of Operations

38

ITEM7A Quantitative and Qualitative Disclosures about Market Risk

54

ITEM8 Financial Statements and Supplementary Data

57

ITEM9 Changes in and Disagreements with Accountants on Accounting and

Financial Disclosure

112

ITEM9A Controls and Procedures

112

ITEM9B Other Information

112

PART III

ITEM10 Directors, Executive Officers and Corporate Governance

113

ITEM11 Executive Compensation

113

ITEM12 Security Ownership of Certain Beneficial Owners and Management and

Related Stockholder Matters

113

ITEM13 Certain Relationships and Related Transactions, and Director

Independence

113

ITEM14 Principal Accounting Fees and Services

113

PART IV

ITEM15 Exhibits, Financial Statement Schedules 113
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FORWARD-LOOKINGINFORMATION

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 physicalsecurity

breaches and other factors detailed herein and in our other Securities and Exchange Commission filings. See "Risk Factors" in Item1A 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 fromthose indicated.

GLOSSARYOF 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 Form10-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.

Dif erential. An adjustment to the price of oil or gas froman 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 fromreservoirs 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 froma given date forward, fromknown 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 froma 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 fromother 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

fromthe 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 fromthe 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 taxrate with consideration of future taxrates already legislated, to pre-taxfuture net cash flows, net of the

taxbasis of the properties involved and utilization of available taxcarryforwards related to proved oil and gas reserves.

Unconventional play. A termused 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 fromnew wells on undrilled acreage, or

fromexisting 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 and2. 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-termthrough 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 programbased on projects that

we expect will enable us to maximize our production and reserve growth at attractive returns. Our capital programis 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 programwith 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 potentialstrategic 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 programin 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 programto 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 fromthe 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 fromthe 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 Wilcoxformations 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 fromthe 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.

RISKMANAGEMENT

Fromtime 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 indexprice exceeds the ceiling and payments fromthe counterparties if the indexprice falls below the

floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the indexprice 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 oilswaps 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:

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:

Commodity and Derivative Type

Weighted-Average

Contract Price Volume Contract Period

Natural gas collars

$3.09 Floor /

$4.12 Ceiling per

Mcf

35.5

Bcf

Jan. 2013 -

Dec. 2013

Natural gas collars

$3.35 Floor /

$4.01 Ceiling per

Mcf

35.5

Bcf

Jan. 2013 -

Dec. 2013

Natural gas collars

$3.40 Floor /

$4.12 Ceiling per

Mcf

17.7

Bcf

Jan. 2013 -

Dec. 2013

Natural gas collars

$3.60 Floor /

$4.17 Ceiling per

Mcf

17.7

Bcf

Jan. 2013 -

Dec. 2013

Natural gas collars

$3.76 Floor /

$4.16 Ceiling per

Mcf

17.7

Bcf

Jan. 2013 -

Dec. 2013

Natural gas collars

$3.86 Floor /

$4.34 Ceiling per

Mcf

17.7

Bcf

Jan. 2013 -

Dec. 2013

Natural gas collars

$5.15 Floor /

$6.20 Ceiling per

Mcf

17.7

Bcf

Jan. 2013 -

Dec. 2013

Crude oilswaps

$101.90 per Bbl 1,095

Mbbl

Jan. 2013 -

Dec. 2013

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
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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% from3,033 Bcfe at December 31, 2011 due to the positive results fromour 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.

10

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.
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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

petroleumengineering staff and audited by Miller and Lents, Ltd. (Miller and Lents), independent petroleumengineers. 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 Form10-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 indexprices, 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 Item8 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 Item1A.

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 PetroleumEngineers.

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 PetroleumEngineers. Miller and Lents is an independent firmof 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 PRICEAND 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 oilsales 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.

ACREAGE

Our interest in both developed and undeveloped properties is primarily in the formof 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

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
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fromapproximately 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.

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.

DRILLINGACTIVITY

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

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

Gross Net

Natural Gas

4,998 4,300.9

Crude Oil

286 209.2

Total

(1)

5,284 4,510.1

(1)

Total percentage of gross operated wells is 88.3%.

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

13

Total

170 117.8 161 96.0 113 87.1
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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 totalsales. In 2011, we did not have any

one customer account for greater than 10% of our totalsales. In 2010, one customer accounted for approximately 11% of our totalsales. 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 maximumrates of production fromoil 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 fromour 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 fromFERC 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 allsales 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 fromFERC 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 fromtheir 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 fromthe 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 fromthe 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 systemfor 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 indexand 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 Indexfor Finished Goods plus 2.65% should be the oil pricing

indexfor the five-year period beginning July 1, 2011. The result of indexing is a "ceiling rate" for each rate, which is the maximumat 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 taxallowance with respect to income for which there is an "actual or

potential income taxliability," to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest

is required to file a taxreturn that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income

taxliability sufficient to support a taxallowance 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 taxallowances.

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 programthat must at a minimuminclude 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 programfor our pipeline systemin 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 programfor 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

maximumcivil 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 maximumallowable 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 fromrules contained in the act, which include

revisions to DOT's civil penalty authority and the requirement that pipelines verify maximumallowable 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 roomto develop written control roommanagement procedures

by August 1, 2011 and implement the procedures by February 1, 2013. The DOT expedited the programimplementation deadline to

October 1, 2011 for most of the requirements, except for certain provisions regarding adequate information and alarmmanagement, which

had a programimplementation deadline of August 1, 2012. We developed and implemented the required control roommanagement

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 fromoil 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 harmthe 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 performplugging 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 fromtreatment 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 severalstrict 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 fromthe 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 oilspills and liability for damages resulting fromsuch 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 severalstrict 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 systemof 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 fromsources 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 fromoil 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 fromthe 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 Item1A.

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 fromsources

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 Item1A.

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 Form10-K, quarterly reports on

Form10-Q, current reports on Form8-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 Roomlocated at

100 F Street, NE, Washington, DC 20549. Information regarding the operation of the Public Reference Roomcan 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.

ITEM1A. RISKFACTORS

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 oilsupply and demand and expectations regarding supply and demand, including the potential

long-termimpact of an abundance of natural gas fromshale (such as that produced fromour 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 PetroleumExporting 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 indexprices; 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 fromour 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 complexand 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 fromthe 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 fromour 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 indexprices, 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 fromthose 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 fromtime 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 af ect 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 fromproved reserves (also potentially including risk-adjusted probable and possible reserves fromtime 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 fromoperations. 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 fromour 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 fromnewly 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-termcapital markets as sources of liquidity for any capital

requirements not satisfied by the cash flow fromoperations or other sources. Future challenges in the global financialsystem, 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 performtheir 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 af ect our financial condition

and reduce our growth rate.

Our future growth prospects are dependent upon our ability to identify optimalstrategies 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 fromthose 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 ef ect 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 oilspill 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 federalsafety 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 fromthese new wells, as well as natural gas

produced fromother 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 af ect 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 fromnatural gas extraction and

production activities that may cause or contribute to significant harmto 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 fromnatural 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 complexand 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 dif icult, 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

fromour 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 momentumin, 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:

•wellsite 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 industrialsites, 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 performoperations, 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 af ect our business.

The threat of terrorismand 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 fromwells served by such facilities untilsuitable arrangements are made to market our

production. Our failure to obtain these services on acceptable terms could materially harmour 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 af ect 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.

Fromtime 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 indexprice exceeds the ceiling and payments fromthe counterparties

if the indexprice falls below

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the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the indexprice 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 Item7 and "Quantitative and Qualitative Disclosures about Market Risk" in Item7A for

further discussion concerning our use of derivatives.

The loss of key personnel could adversely af ect 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 fromoil 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 fromthe 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 wellsites 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 wellby-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 fromnatural 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 maximumachievable 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

wellsite 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 fromcertain 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 fromthe 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 fromshale

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 Programunder 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 fromwellsites 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 sixkey

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 fromnew 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 fromcrude oil. Also, according to the

EPA, the final motor vehicle GHGstandards will trigger construction and operating permit requirements for stationary sources. Thus, on

June 3, 2010, EPA issued a final rule to address permitting of GHGemissions fromstationary sources under the Clean Air Act's Prevention

of Significant Deterioration ("PSD") and Title Vprograms. This final rule "tailors" the PSD and Title Vprograms to apply to certain

stationary sources of GHGemissions in a multistep process, with the largest sources first subject to permitting. In addition, on November 8,

2010, EPA finalized new GHGreporting requirements for upstreampetroleumand natural gas systems, which will be added to EPA's GHG

Reporting Rule. Facilities containing petroleumand natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year were

required to report annual GHGemissions to EPA, for the first time by September 28, 2012. We submitted our report in compliance with the

deadline.

In addition, Congress has fromtime 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 controlsystems, 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 ef ect on our financial position,

results of operations, and cash flows.

Substantive changes to existing federal income taxlaws have been proposed that, if adopted, would repeal many taxincentives 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 taxdeduction 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 fromtransactions 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 unlawfulstock repurchases or redemptions; and

•for any transaction fromwhich 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 frombringing a lawsuit against directors for breach of their duty of care, even though such an action, if

successful, might otherwise have benefited our stockholders.

ITEM1B. UNRESOLVED STAFF COMMENTS

None.

ITEM3. 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

Item8 of this Annual Report on Form10-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 Item8 of this Annual Report on Form10-K is incorporated by reference in response to this item.

We have received a number of Notices of Violation fromthe 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 fromthe 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.

ITEM4. MINESAFETYDISCLOSURES

Not applicable.

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EXECUTIVEOFFICERS OFTHEREGISTRANT

The following table shows certain information as of February 21, 2013 about our executive officers, as such termis defined in Rule 3b-7

of the Securities Exchange Act of 1934, and certain of our other officers.

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. Cunninghamjoined 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. Cunninghamwas Regional Counsel-Southern

Division at Chesapeake Energy from2006 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 Petroleumand most recently Chesapeake Energy fromApril 2007 until he joined the Company. He holds a Bachelor of Business

Administration degree in PetroleumLand Management fromthe 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. fromJanuary 2007, where she was responsible for

corporate governance and SEC and NYSE compliance matters. Ms. Shearer received her J.D. degree fromThe University of Texas School of

Law in 1992 and was primarily in private practice untilshe joined KBR.

Name Age Position

Officer

Since

Dan O. Dinges 59 Chairman, President and Chief Executive

Officer

2001

Scott C.

Schroeder

50 Vice President, Chief Financial Officer and

Treasurer

1997

G. Kevin

Cunningham

59 Vice President, General Counsel 2010

Robert G.

Drake

65 Vice President, Information Services and

Operational Accounting

1998

Jeffrey W.

Hutton

57 Vice President, Marketing 1995

Todd L. Liebl 55 Vice President, Land and Business

Development

2012

Steven W.

Lindeman

52 Vice President, Engineering and

Technology

2011

James M. Reid 61 Vice President, Regional Manager South

Region

2009

Phillip L.

Stalnaker

53 Vice President, Regional Manager North

Region

2009

Todd M.

Roemer

42 Controller 2010

Deidre L.

Shearer

45 Corporate Secretary and Managing

Counsel

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PART II

ITEM5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES

OFEQUITYSECURITIES

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 formof 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.

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

ISSUER PURCHASES OFEQUITYSECURITIES

On October 26, 2006, our Board of Directors authorized a share repurchase programunder 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.

35

High Low Dividends

2012

First Quarter

$ 41.36 $ 30.25 $ 0.02

SecondQuarter

$ 41.24 $ 29.54 $ 0.02

ThirdQuarter

$ 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
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PERFORMANCEGRAPH

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 Indexfor the period December 2007 through December 2012. The graph assumes that the

value of the investment in our common stock and in each indexwas $100 on December 31, 2007 and that all dividends were reinvested.

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 materialsubject to Regulation 14A.

36

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
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ITEM6. 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 Item7, and the Consolidated

Financial Statements and related Notes in Item8.

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 fromoperations

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

Dilutedearnings 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-termdebt

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
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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 ef ective January 25, 2012.
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ITEM7. 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

Form10-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% from2011. 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 programand 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 fromnatural gas to liquids drilling and normal production declines. Crude

oil/condensate/NGL production increased by 964 Mbbls, or 67%, from1,443 Mbbls in 2011 to 2,407 Mbbls in 2012. This increase was

primarily the result of increased production resulting fromour Eagle Ford Shale drilling programin 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 fromcommodity derivatives. For information about the impact of these

derivatives on realized prices, refer to "Results of Operations" in Item7. Commodity prices are determined by many factors that are outside

of our control. Historically, commodity prices have been volatile, and we expect themto 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-termsuccess. 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 Item1A.

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 programin 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

programfor 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 programincludes between $950.0 million and

$1.0 billion in capital and exploration expenditures. Funding of the programis 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 andLiquidity

Our primary sources of cash in 2012 were fromfunds generated fromthe sale of natural gas and crude oil production (including hedge

realizations), proceeds fromthe 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. Fromtime 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.

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-termassets 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.

39

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
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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 from2011 to 2012 and decreased by $126.1 million from2010 to 2011.

The increase from2011 to 2012 was due to a decrease of $234.3 million of proceeds fromthe 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

from2010 to 2011 was due to an increase of $160.1 million of proceeds fromthe 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 from2011 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 from2010 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 fromSeptember 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:

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 andExploration Expenditures

On an annual basis, we generally fund most of our capital and exploration expenditures, excluding any significant property acquisitions,

with cash generated fromoperations 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:

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 programincludes 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 capitalspending 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

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.

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
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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:

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 Ef orts 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

Payments Due by Year

(In thousands) Total 2013

2014

to 2015

2016

to 2017

2018 &

Beyond

Long-termdebt

$ 1,087,000 $ 75,000 $ — $ 345,000 $ 667,000

Interest on longtermdebt

(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 dif er 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.
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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 petroleumengineering staff and audited by Miller & Lents, independent petroleumengineers,

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 Item8.

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 fromlower 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 fromproved reserves (also potentially including risk-adjusted probable and possible reserves fromtime 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 fromthree 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 longlived 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 fromthe 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 fromour 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 fromcounterparties 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-termemployee 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 liabilityclassified 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 interimand 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 interimand 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 Item1 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 minimumannual

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 Item1A. 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 indexdeclines, 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 indexprices 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.

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

Year Ended

December 31, Variance

Revenue Variances (In thousands) 2012 2011 Amount Percent

Natural gas

(1)

$ 934,134 $ 797,482 $ 136,652 17%

Crude oil and condensate

227,933 125,972 101,961 81%

Brokered natural gas

34,005 51,190 (17,185 ) (34)%

Other

8,968 6,185 2,783 45%

(1) Natural gas revenues exclude the unrealized loss of $0.5 million and $1.0 million from the change in fair value of

our derivatives not designated as hedges in 2012 and 2011, respectively.

Year Ended

December 31, Variance Increase

(Decrease)

2012 2011 Amount Percent (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.
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production in the Marcellus Shale associated with our drilling programand 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 fromnatural 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 programin south Texas and the Marmaton oil play in Oklahoma, coupled with higher realized oil prices.

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Brokered Natural Gas

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 fromthe 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:

48

Year Ended

December 31, Variance Price and

Volume

Variances

2012 2011 Amount Percent (In thousands)

BrokeredNatural 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 )

BrokeredNatural 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 )

Year Ended

December 31,

(In thousands) 2012 2011

Cash FlowHedges

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

Total costs and expenses fromoperations increased by $212.7 million from2011 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 from2011 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 taxexpense due

to fewer production taxrefunds 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.

49

Year Ended

December 31, Variance

(In thousands) 2012 2011 Amount Percent

Operating andOther 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 taxexpense

106,110 112,779 (6,669 ) (6)%
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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 liabilitybased 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 taxexpense decreased by $6.7 million in 2012 compared to 2011 primarily due a lower effective taxrate partially offset by

increased pretaxincome. The effective taxrates for 2012 and 2011 were 44.6% and 48.0%, respectively. The effective taxrate 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.

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 programin northeast Pennsylvania, partially offset by decreases in production primarily in east

Year Ended

December 31, Variance

Revenue Variances (In thousands) 2011 2010 Amount Percent

Natural gas

(1)

$ 797,482 $ 713,872 $ 83,610 12%

Crude oil and condensate

125,972 79,091 46,881 59%

Brokered natural gas

51,190 65,281 (14,091 ) (22)%

Other

6,185 5,086 1,099 22%

(1) Natural Gas Revenues exclude the unrealized loss of $1.0 million and $0.2 million from the change in fair value of

our derivatives not designated as hedges in 2011 and 2010, respectively.

Year Ended

December 31, Variance Increase

(Decrease)

2011 2010 Amount Percent (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
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and south Texas due to normal production declines, the sale of certain oil and gas properties in the Rockies and a shift fromnatural 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 programin 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

The decreased brokered natural gas margin of $1.5 million is primarily a result of a decrease in brokered volumes coupled with a

decrease in the sales price that slightly outpaced the decrease in purchase price.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the increase / (decrease) to operating revenues fromthe 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:

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Year Ended

December 31, Variance Price and

Volume

Variances

2011 2010 Amount Percent (In thousands)

BrokeredNatural 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 )

BrokeredNatural 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 )

Year Ended

December 31,

(In thousands) 2011 2010

Cash FlowHedges

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

Total costs and expenses fromoperations increased by $33.4 million from2010 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 systemin northeast Pennsylvania in the fourth quarter of 2010.

•Transportation and gathering increased by $54.3 million primarily due to the commencement of various firmtransportation and gathering

arrangements in 2011, primarily in northeast Pennsylvania.

•Brokered natural gas decreased by $12.6 million from2010 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 taxrefunds and credits received in 2011 on

qualifying wells, lower ad valoremtaxexpense due to lower natural gas prices and property values and lower franchise taxexpense.

•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

fromincreased capitalspending 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

Year Ended

December 31, Variance

(In thousands) 2011 2010 Amount Percent

Operating andOther 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 taxexpense

112,779 95,112 17,667 19%
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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 from2011 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 fromthe 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 fromthe sale of our

Pennsylvania gathering infrastructure, $40.7 million fromthe 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 taxexpense increased by $17.7 million in 2011 compared to 2010 primarily due to increased pretaxincome and a slightly higher

effective taxrate. The effective taxrates for 2011 and 2010 were 48.0% and 47.9%, respectively. The effective taxrate 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.

ITEM7A. QUANTITATIVEAND QUALITATIVEDISCLOSURES 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 andHedging 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 materialspeculative risks. All of our derivatives are used for risk management purposes and are not held for trading

purposes. Under the collar agreements, if the indexprice rises above the ceiling price, we pay the counterparty. If the indexprice 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

WeightedAverage

Contract

Price Volume

Contract

Period

Net

Unrealized

Gain / (Loss)

(In

thousands)

Natural gas collars

$3.09

Floor /

$4.12

Ceiling

per

Mcf

35.5

Bcf

Jan.

2013 - Dec.

2013 $ (2,807 )

Natural gas collars

$3.35

Floor /

$4.01

Ceiling

per

Mcf

35.5

Bcf

Jan.

2013 - Dec.

2013 (1,021 )

Natural gas collars

$3.40

Floor /

$4.12

Ceiling

per

Mcf

17.7

Bcf

Jan.

2013 - Dec.

2013 287

Natural gas collars

$3.60

Floor /

$4.17

Ceiling

per

Mcf

17.7

Bcf

Jan.

2013 - Dec.

2013 2,290

Natural gas collars

$3.76

Floor /

$4.16

Ceiling

per

Mcf

17.7

Bcf

Jan.

2013 - Dec.

2013 5,765

$3.86

Floor /

$4.34

Ceiling

per

Mcf

17.7

Bcf

Jan.

2013 - Dec.

2013 7,586
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The amounts set forth under the net unrealized gain / (loss) column in the table above represent our total unrealized derivative position

at December 31, 2012 and exclude the impact of nonperformance risk. Nonperformance risk was primarily evaluated by reviewing credit

default swap spreads for the various financial institutions in which we have derivative transactions, while our non-performance risk is

evaluated using a market credit spread provided by one of our banks.

During 2012, natural gas and crude oilswaps covered 96.0 Bcf, or 38%, and 1,709 Mbbl, or 76%, of natural gas and crude oil production

at an average price of $5.22 per Mcf and $100.12 per Bbl, respectively. Natural gas basis swaps covered 17 Bcf, or 7%, of our natural gas

production at an average price of $(0.25) per Mcf. Natural gas collars with a floor price of $3.60 per Mcf and a ceiling price of $4.17 per Mcf

covered 3.0 Bcf, or 1%, of our natural gas production at an average price of $3.70 per Mcf.

We are exposed to market risk on derivative instruments to the extent of changes in market prices of natural gas and crude oil. However,

the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the

commodity. Although notional contract amounts are used to express the volume of natural gas agreements, the amounts that can be subject

to credit risk in the event of non-performance by third parties are substantially smaller. We do not anticipate any material impact on our

financial results due to non-performance by third parties. Our primary derivative contract counterparties are Bank of America, Bank of

Montreal, Goldman Sachs, JPMorgan and Morgan Stanley.

55

Natural gas collars

Natural gas collars

$5.15

Floor /

$6.20

Ceiling

per

Mcf

17.7

Bcf

Jan.

2013 - Dec.

2013 29,090

Crude oilswaps

$101.90

per Bbl

1,095

Mbbl

Jan.

2013 - Dec.

2013 9,482

$ 50,672
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Fair Market Value of Other Financial Instruments

The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between

willing parties. The carrying amounts reported in the Consolidated Balance Sheet for cash and cash equivalents, accounts receivable, and

accounts payable approximate fair value due to the short-termmaturities of these instruments.

The fair value of long-termdebt 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 (premiumor 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-termdebt are as follows:

56

December 31, 2012 December 31, 2011

(In thousands)

Carrying

Amount

Estimated Fair

Value

Carrying

Amount

Estimated Fair

Value

Long-termdebt

$ 1,087,000 $ 1,213,474 $ 950,000 $ 1,082,531

Current maturities

(75,000 ) (77,175 ) — —

Long-termdebt, excluding

current maturities

$ 1,012,000 $ 1,136,299 $ 950,000 $ 1,082,531
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ITEM8. FINANCIAL STATEMENTS AND SUPPLEMENTARYDATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

57

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 ACCOUNTINGFIRM

To the Boardof Directors andStockholders 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 financialstatements, 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 Item9A. Our responsibility is to

express opinions on these financialstatements 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 performthe audits to obtain reasonable assurance about whether the financialstatements are free

of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of

the financialstatements included examining, on a test basis, evidence supporting the amounts and disclosures in the financialstatements,

assessing the accounting principles used and significant estimates made by management, and evaluating the overall financialstatement

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 financialstatements 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 financialstatements 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 financialstatements.

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

58
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CABOT OIL & GAS CORPORATION

CONSOLIDATED BALANCESHEET

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-termdebt

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-termdebt

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
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The accompanying notes are an integral part of these consolidated financialstatements.

59

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 )

Totalstockholders' equity

2,131,447 2,104,768

$ 4,616,313 $ 4,331,493
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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

OPERATINGREVENUES

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

OPERATINGEXPENSES

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 taxexpense

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
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The accompanying notes are an integral part of these consolidated financialstatements.

60

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
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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVEINCOME

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.
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The accompanying notes are an integral part of these consolidated financialstatements.

61

(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.
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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF CASHFLOWS

Year Ended December 31,

(In thousands) 2012 2011 2010

CASH FLOWS FROM OPERATINGACTIVITIES

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 taxexpense

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 INVESTINGACTIVITIES

Capital expenditures

(927,977 ) (891,277 ) (857,251 )

Proceeds fromsale 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 FINANCINGACTIVITIES
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The accompanying notes are an integral part of these consolidated financialstatements.

62

Borrowings fromdebt

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
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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

(In thousands, except per share amounts)

Common

Shares

Stock

Par

Treasury

Shares

Treasury

Stock

Paid-In

Capital

Accumulated

Other

Comprehensive

Income /

(Loss)

Retained

Earnings Total

Balance at December 31, 2009

207,712 $ 20,772 404 $ (3,349 ) $ 695,183 $ 42,436 $ 1,057,472 $ 1,812,514

Net income — — — — — — 103,386 103,386

Exercise ofstock options and stock appreciation

rights

78 8 — — 762 — — 770

Tax benefit ofstock-based compensation — — — — 108 — — 108

Stock amortization and vesting

630 62 — — 12,868 — — 12,930

Sale ofstock 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 ofstock options and stock appreciation

rights

159 16 — — (1,762 ) — — (1,746 )

Stock amortization and vesting

440 44 — — 13,906 — — 13,950

Sale ofstock 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 ofstock 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
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The accompanying notes are an integral part of these consolidated financialstatements.

63

210,430 $ 21,043 404 $ (3,349 ) $ 716,609 $ 23,880 $ 1,373,264 $ 2,131,447
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NOTES TO THECONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation andNature 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 financialstatements include the accounts of the Company and its subsidiaries after eliminating allsignificant

intercompany balances and transactions. Certain reclassifications have been made to prior year statements to conformwith 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 formof 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 interimand annual periods beginning on or after

January 1, 2013. This guidance will primarily impact the Company's disclosures associated with its commodity derivatives. The Company

does not expect this guidance to have any impact on its consolidated financial position, results of operations or cash flows.

In January 2013, the FASB issued ASU No. 2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities." The

amendments in this update clarify that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with ASC 815,

Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and

securities borrowing and securities lending transactions that are either offset in accordance with ASC 210-20-45 or ASC 815-10-45 or subject

to an enforceable master netting arrangement or similar agreement. The amendments are effective during interimand annual periods

beginning on or after January 1, 2013. This guidance will primarily impact the Company's disclosures

64
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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 andCash Equivalents

The Company considers all highly liquid short-terminvestments 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 fromthe Company under imbalance arrangements are recorded at actualselling or purchase prices, as the case may be, and are

adjusted monthly to market prices.

Equity MethodInvestment

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 financialstatements 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 andEquipment

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 from10 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 fromproved reserves (also potentially including risk-adjusted probable and possible reserves fromtime 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

Fromtime 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 fromoperations. 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 itemassociated 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 itemsince 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 themon 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 taxassets and

liabilities are recorded for the estimated future taxconsequences attributable to the differences between the financial carrying amounts of

existing assets and liabilities and their respective taxbasis. Deferred taxassets and liabilities are measured using the taxrate in effect for the

year in which those temporary differences are expected to reverse. The effect of a change in taxrates on deferred taxassets and liabilities is

recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred taxassets if it is more likely than

not that the related taxbenefits will not be realized.

The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding taxpositions 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 taxreturn. The taxbenefit froman uncertain taxposition 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

taxbenefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement.

The effective taxrate and the taxbasis of assets and liabilities reflect management's estimates of the ultimate outcome of various tax

uncertainties.

The Company recognizes accrued interest related to uncertain taxpositions in Interest expense and other and accrued penalties related

to such positions in General and administrative expense in the Consolidated Statement of Operations.

Stock-BasedCompensation

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 taxbenefit for stock-based compensation is included as both a cash inflow fromfinancing activities and a cash outflow from

operating activities in the Consolidated Statement of Cash Flows. The Company recognizes a taxbenefit only to the extent it reduces the

Company's income taxes payable. The Company did not recognize a taxbenefit 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 andConcentration 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 totalsales. In 2011, the

Company did not have any one customer account for greater than 10% of the Company's totalsales. In 2010, one customer accounted for

approximately 11%, of the Company's totalsales.

Use of Estimates

In preparing financialstatements, 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 financialstatements, 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 fromthose estimates.

2. Properties andEquipment, Net

Properties and equipment, net are comprised of the following:

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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 andEquipment, Net (Continued)

Capitalized Exploratory Well Costs

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

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

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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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

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
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2. Properties andEquipment, 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 frommarket 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 andEquipment, 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
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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 andCredit Agreements

The Company's debt consisted of the following:

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 FixedRate 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:

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 minimumannual 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 premiumof $2.8 million which was included in Interest expense and other in the Consolidated Statement of

Operations.

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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

Principal Term

Maturity

Date Coupon

Tranche 1

$ 75,000,000 10-year July 2011 7.26%

Tranche 2

$ 75,000,000 12-year July 2013 7.36%

Tranche 3

$ 20,000,000 15-year July 2016 7.46%
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4. Debt andCredit Agreements (Continued)

6.51% Weighted-Average FixedRate 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:

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 minimumannual 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 GSenior 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 FixedRate 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:

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.

75

Principal Term Maturity Date Coupon

Tranche 1

$ 245,000,000 10-year July 2018 6.44%

Tranche 2

$ 100,000,000 12-year July 2020 6.54%

Tranche 3

$ 80,000,000 15-year July 2023 6.69%

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%
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4. Debt andCredit 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 termof 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 termof the amended

credit facility.

The amended credit facility is unsecured. The available credit line is subject to adjustment fromtime 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 fromcertain 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 sixmonths 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 interimredetermination 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:

The amended credit facility provides for a commitment fee on the unused available balance at annual rates ranging from0.375% 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):

(Ma)aintenance of a minimumannual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

76

Debt Percentage

<25% 325% <50% 350% <75% 375% <90% 390%

Eurodollar loans

1.50% 1.75% 2.00% 2.25% 2.50%

ABR loans

0.50% 0.75% 1.00% 1.25% 1.50%
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4. Debt andCredit Agreements (Continued)

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

(Mc)aintenance of a current ratio of 1.0 to 1.0.

(Pd)rohibition 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 MethodInvestment

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 taxqualified 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 taxlaws, referred to as the supplemental non-qualified pension arrangements (nonqualified 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:

Amounts Recognized in the Balance Sheet

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.
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Amounts recognized in the balance sheet consist of the following:

79

December 31,

(In thousands) 2012 2011 2010

Current liabilities

$ — $ 5,070 $ 603

Long-termliabilities — — 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:

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

Non-Qualified Pension Plans

December 31,

(In thousands) 2012 2011 2010

Prior service cost

$ — $ 221 $ 1,267

Net actuarial loss — 13,082 12,248

$ — $ 13,303 $ 13,515

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 QualifiedPlan Assets

andBenefit Obligations Recognizedin

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 )
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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.

80

(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.
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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:

Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet consist of the following:

Amounts Recognized in Accumulated Other Comprehensive Income

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

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 )

December 31,

(In thousands) 2012 2011 2010

Current liabilities

$ 1,304 $ 1,261 $ 1,085

Long-termliabilities

38,864 38,708 30,862

$ 40,168 $ 39,969 $ 31,947

December 31,

(In thousands) 2012 2011 2010

Transition obligation

$ — $ — $ 632

Net actuarial loss

11,269 14,166 8,408
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$ 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 fromaccumulated 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

Assumptions

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

Coverage provided to participants age 65 and older is under a fully-insured arrangement. The Company subsidy is limited to 60% of the

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

Recognizedin 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 )

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.
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expected annual fully- insured premiumfor 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 onepercentage-point change in assumed health care cost trend rates would have the following effects:

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:

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-fordollar, up to the maximumIRS limit, on the first sixpercent of an employee's pretaxearnings. 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.

DeferredCompensation 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

83

(In thousands)

1-PercentagePoint Increase1-PercentagePoint Decrease

Effect on total of service and interest cost

$ 588 $ (470 )

Effect on postretirement benefit obligation

6,451 5,241

(In thousands)

2013

$ 1,330

2014

1,465

2015

1,568

2016

1,665

2017

1,772

Years 2018 - 2022

11,372
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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 spectrumfromequity 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 sumor 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 fromthe 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 taxexpense is summarized as follows:

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

85

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 taxexpense

$ 106,110 $ 112,779 $ 95,112

Year Ended December 31,

(Dollars in thousands) 2012 2011 2010

Statutory federal income taxrate

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 taxadjustment related to change in

overallstate taxrate

13,596 19,068 18,973

Other, net

(339 ) 2,406 26

Total income taxexpense

$ 106,110 $ 112,779 $ 95,112
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7. Income Taxes (Continued)

The taxeffects of temporary differences that resulted in significant portions of the deferred taxliabilities and deferred taxassets were as

follows:

As of December 31, 2012, the Company had alternative minimumtaxcredit 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 minimumtaxin 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. Taxbenefits related to employee stock-based compensation included in net operating loss

carryforwards but not reflected in deferred taxassets as of December 31, 2012 are approximately $66.9 million.

Uncertain Tax Positions

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

December 31,

(In thousands) 2012 2011

DeferredTax 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

DeferredTax Assets

Alternative minimumtaxcredit

125,862 101,290

Net operating loss

137,422 113,496

Foreign taxcredits

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 taxliabilities

$ 887,875 $ 857,724

Year Ended

December 31,

(In thousands) 2012 2011 2010

Unrecognized taxbenefit balance at beginning of year

$ — $ — $ 500

Additions based on taxprovisions related to the current

year — — —

Additions for taxpositions of prior years — — —

Reductions for taxpositions of prior years

— — (500 )
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During 2010, unrecognized taxbenefits 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 taxyears that were under audit by the IRS. This reduction did not materially affect the

effective taxrate. As of

86

Settlements — — —

Unrecognized taxbenefit balance at end of year

$ — $ — $ —
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7. Income Taxes (Continued)

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

The Company files income taxreturns 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 andContingencies

Transportation Agreements

The Company has entered into certain natural gas and liquids transportation agreements with various pipelines with initial terms

ranging fromapproximately four to 23 years. Under certain of these agreements, the Company is obligated to transport minimumdaily

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 firmcapacity 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 minimumdaily 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:

Drilling Rig Commitments

During 2012, the Company did not enter into any new long-termdrilling rig commitments. The existing commitments that commenced in

the fourth quarter of 2011 relate to the Company's capital programin the Marcellus Shale and have original terms ranging fromtwo to three

years. The future minimumcommitments 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 noncancelable 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.

87

(In thousands)

2013

$ 94,714

2014

98,145

2015

115,203

2016

126,973

2017

121,923

Thereafter

1,156,294

$ 1,713,252
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8. Commitments andContingencies (Continued)

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

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

88

(In thousands)

2013

$ 5,106

2014

4,652

2015

3,624

2016

730

2017

192

Thereafter —

$ 14,304
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8. Commitments andContingencies (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:

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.

89

(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
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10. Supplemental Cash FlowInformation

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

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 AuthorizedShares

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 programunder 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 totalshares 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.

DividendRestrictions

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 fromoperations, 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.

90

Year Ended December 31,

(In thousands) 2012 2011 2010

Interest

$ 64,970 $ 62,353 $ 64,342

Income taxes

22,501 65,352 (1,050 )
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12. Stock-BasedCompensation

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.

RestrictedStock 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 termis 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 from6.0% 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:

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

91

Restricted Stock Awards Shares

WeightedAverage Grant

Date Fair

Value per Share

WeightedAverage

Remaining

Contractual

Term (in years)

Aggregate

Intrinsic Value

(in thousands)

(1)

Outstanding at December 31,

2011

238,194 $ 18.35

Granted

6,550 36.84

Vested

(201,400 ) 18.05

Forfeited

(7,590 ) 17.60

Outstanding at December 31,

2012

35,754 $ 23.64 0.8 $ 1,778

(1)

The aggregate intrinsic value ofrestricted 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.
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12. Stock-BasedCompensation (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.

RestrictedStock Units

Restricted stock units are granted fromtime 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:

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.

92

Restricted Stock Units Units

WeightedAverage Grant

Date Fair Value

per Unit

WeightedAverage

Remaining

Contractual

Term (in years)

(2)

Aggregate

Intrinsic Value

(in thousands)

(1)

Outstanding at December 31,

2011

343,654 $ 15.75

Granted and fully vested

38,304 36.55

Issued

(124,224 ) 17.11

Forfeited — —

Outstanding at December 31,

2012

257,734 $ 18.19 — $ 12,820

(1)

The aggregate intrinsic value ofrestricted 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.
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12. Stock-BasedCompensation (Continued)

The following table is a summary of stock option activity:

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 termof seven years. All of these awards have gradedvesting 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:

The expected termwas derived by reviewing minimumand maximumexpected termoutputs fromthe Black-Scholes model based on

Year Ended December 31,

2012 2011 2010

Stock Options Shares

WeightedAverage

Exercise

Price Shares

WeightedAverage

Exercise

Price Shares

WeightedAverage

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

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
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award type and employee type. This termrepresents 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 termthrough

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 termas measured on the grant date. The expected dividend percentage assumes that the

Company will continue to pay a consistent level of dividend each quarter.

93
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12. Stock-BasedCompensation (Continued)

The following is a summary of SAR activity:

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 from0% 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.

94

Year Ended December 31,

2012 2011 2010

Stock Appreciation Rights Shares

WeightedAverage

Exercise

Price Shares

WeightedAverage

Exercise

Price Shares

WeightedAverage

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.
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12. Stock-BasedCompensation (Continued)

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

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

95

Performance Share Awards Shares

WeightedAverage Grant

Date Fair Value

per Share

(1)

WeightedAverage

Remaining

Contractual

Term (in years)

Aggregate

Intrinsic Value

(in thousands)

(2)

Outstanding at

December 31, 2011

2,441,566 $ 15.31

Granted

518,602 33.62

Issued and fully

vested

(1,358,564 ) 11.95

Forfeited

(42,850 ) 24.22

Outstanding at

December 31, 2012

1,558,754 $ 24.08 1.1 $ 77,532

(1)

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

(2)

The aggregate intrinsic value of performance share awards is calculated by multiplying the closing market price of the

Company's stock on December 31, 2012 by the number of non-vested performance share awards outstanding.
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12. Stock-BasedCompensation (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-BasedCompensation (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:

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:

The long-termliability 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-termliability, 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.

DeferredPerformance 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

97

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%

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%
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12. Stock-BasedCompensation (Continued)

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

fromDecember 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 (interimtrigger 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 interimtrigger is met or 50% of base salary if the final trigger is met (or an incremental 30% of base

salary if the Company paid interimdistributions upon achievement of the interimtrigger).

In accordance with the Plan, in the event the interimor 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 interimtrigger 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 andHedging 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 materialspeculative 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:

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 financialstatements:

Ef ect of Derivative Instruments on the Consolidated Balance Sheet

Commodity and Derivative Type

Weighted-Average

Contract Price Volume

Contract

Period

Natural gas collars

$3.09

Floor /

$4.12

Ceiling

per

Mcf 35.5 Bcf

Jan.

2013 -

Dec.

2013

Natural gas collars

$3.35

Floor /

$4.01

Ceiling

per

Mcf 35.5 Bcf

Jan.

2013 -

Dec.

2013

Natural gas collars

$3.40

Floor /

$4.12

Ceiling

per

Mcf 17.7 Bcf

Jan.

2013 -

Dec.

2013

Natural gas collars

$3.60

Floor /

$4.17

Ceiling

per

Mcf 17.7 Bcf

Jan.

2013 -

Dec.

2013

Natural gas collars

$3.76

Floor /

$4.16

Ceiling

per

Mcf 17.7 Bcf

Jan.

2013 -

Dec.

2013

Natural gas collars

$3.86

Floor /

$4.34

Ceiling

per

Mcf 17.7 Bcf

Jan.

2013 -

Dec.

2013

Natural gas collars

$5.15

Floor /

$6.20

Ceiling

per

Mcf 17.7 Bcf

Jan.

2013 -

Dec.

2013

Crude oilswaps

$101.90

per

Bbl 1,095 Mbbl

Jan.

2013 -

Dec.

2013

Fair Values of Derivative Instruments
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Asset Derivatives Liability Derivatives

December 31, December 31,

Balance Sheet

Location 2012 2011

Balance Sheet

(In thousands) Location 2012 2011

Derivatives

Designatedas

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

Designatedas

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 andHedging 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-taxincome associated with its commodity hedges from

Accumulated other comprehensive income to the Consolidated Statement of Operations over the next 12 months.

Ef ect of Derivative Instruments on the Consolidated Statement of Operations

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.

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 fromseparate

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

financialstatements. 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

100

Amount of Gain (Loss)

Recognized in OCI on

Derivative (Effective Portion)

Amount of Gain (Loss)

Reclassified from Accumulated

OCI into Income (Effective

Portion)

Year Ended December 31,

Location of Gain

(Loss)

Reclassified from

Accumulated

OCI into Income

(In thousands)

Year Ended December 31,

Derivatives Designated

as Hedging Instruments

(In thousands) 2012 2011 2010 2012 2011 2010

Commodity

Contracts

$ 88,705 $ 267,667 $ 75,655 Natural gas

revenues

$ 225,108 $ 84,937 $ 154,960

Crude oil and

condensate

revenues

11,218 1,403 18,030

$ 236,326 $ 86,340 $ 172,990

Derivatives Not Designated Year Ended December 31,

as Hedging Instruments

(In thousands)

Location of Gain (Loss)

Recognized in Income on

Derivative 2012 2011 2010

Commodity Contracts Natural gas revenues $ (494 ) $ (965 ) $ (226 )
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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 allsignificant inputs are

observable, either directly or indirectly for substantially the full termof 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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14. Fair Value Measurements (Continued)

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
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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 fromthe 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 termas applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple

quotes obtained fromcounterparties 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.

102

Derivative

contracts — — 385 385

Total liabilities

$ 20,187 $ — $ 385 $ 20,572
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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:

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-termmaturities 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-termdebt 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 (premiumor 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-termdebt is deemed to use Level 3 inputs.

103

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.
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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-termdebt are as follows:

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:

104

December 31, 2012 December 31, 2011

(In thousands)

Carrying

Amount

Estimated

Fair Value

Carrying

Amount

Estimated

Fair Value

Long-termdebt

$ 1,087,000 $ 1,213,474 $ 950,000 $ 1,082,531

Current maturities

(75,000 ) (77,175 ) — —

Long-termdebt, excluding current

maturities

$ 1,012,000 $ 1,136,299 $ 950,000 $ 1,082,531

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. AccumulatedOther Comprehensive Income / (Loss)

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

105

(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 andGas 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 fromtime 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 financialstatement 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 indexprices, 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

ProvedDevelopedReserves

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

ProvedUndevelopedReserves

December 31, 2009
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107

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 ofset 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 ofset by (i) a downward
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Table of Contents

CapitalizedCosts Relating to Oil andGas 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.

Exhibit 10.6

CABOT OIL & GAS CORPORATION

2004 INCENTIVEPLAN

NON-EMPLOYEEDIRECTOR RESTRICTED STOCKUNIT 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 RestrictedStock 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 fromservice 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. DividendCredits. 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

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 ofreserves 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 ofset 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.

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
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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 formas 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 whomshares 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 fromtime 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

1

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 formof 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 formof 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 sixmonths fromthe 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.

2

Exhibit 10.2

CABOT OIL & GAS CORPORATION
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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 themarising 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 willserve or continue to serve the Company free fromundue concern that they will not be so

indemnified; and

WHEREAS, Indemnitee is willing to serve, continue to serve and to take on additionalservice 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 fromsuch 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 fromtime 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 himor 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

1

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 himor 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
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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 himor 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 himor 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 himor 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 fromIndemnitee requesting such advance or advances fromtime to time, whether prior to or after final

2

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 shallsubmit 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 Controlshall 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 quorumor (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
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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 fromdisclosure 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 Counselshall be selected as provided in this Section 8(c). If a Change of Controlshall not have

occurred, the Independent Counselshall be selected by the Board of Directors, and the Company shall give written notice to Indemnitee

advising himof the identity of the Independent Counselso selected. If a Change of Controlshall 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

Counselso selected. In either event, Indemnitee or the

3

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 Counselso selected does not meet the requirements of “Independent Counsel” as defined in Section 17 of this Agreement,

and the objection shallset forth with particularity the factual basis of such assertion. If such written objection is timely made, the

Independent Counselso 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 Counselshall 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 whoman 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 Counselshall 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 Ef ect of Certain Proceedings.

(a) If a Change of Controlshall 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
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the stockholders pursuant to Section 8(b) of this Agreement and if (A) within 15 days after receipt by the Company of the

4

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 Controlshall 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

5

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.
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(d) The Company shall be precluded fromasserting 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 shallstipulate 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 fromthe

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 himin 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 maximumextent of the coverage available for any such similarly situated

director, officer or employee under such policy or policies.

6

(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.
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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 claimtherein, brought or made by himagainst the Company except for any claimor 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.

7

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 whomenforceability 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 originalsignature.

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 fromthe 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

(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,
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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

8

directors, as the case may be, of the entity resulting fromsuch 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

fromsuch Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting fromsuch

Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common

equity of the entity resulting fromsuch 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 fromsuch 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 claimfor 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.

9

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 shallsuch waiver constitute a continuing waiver.

Section 20. Notice by Indemnitee. Indemnitee agrees promptly to notify the Company in writing upon being served with any
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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 whomsaid 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 fromtime 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 fromindemnifying 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 federalsecurities 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.

10

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:
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11

Costs Incurredin Oil andGas Property Acquisition, Exploration andDevelopment Activities

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

StandardizedMeasure of DiscountedFuture Net Cash Flows Relating to ProvedOil andGas 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 fromthose required to be used in these calculations.

108

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
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•Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly fromthe

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 indexprices, 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 taxexpense was computed by applying year end statutory taxrates to future pretaxnet cash flows,

less the taxbasis of the properties involved and utilization of available taxcarryforwards 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:

109

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 taxexpenses

(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 StandardizedMeasure of DiscountedFuture Net Cash Flows Relating to ProvedOil andGas Reserves

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

110

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)

QUARTERLYFINANCIAL INFORMATION

111

(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

Dilutedearnings 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 ofset 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

ef ective 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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ITEM9. CHANGES IN AND DISAGREEMENTS WITHACCOUNTANTS ON ACCOUNTINGAND FINANCIAL DISCLOSURE

None.

ITEM9A. CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls andProcedures andChanges 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 financialstatements 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.

ITEM9B. OTHER INFORMATION

None.

112
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PART III

ITEM10. DIRECTORS, EXECUTIVEOFFICERS AND CORPORATEGOVERNANCE

The information required by this Itemis incorporated by reference to the Company's definitive Proxy Statement in connection with the

2013 annualstockholders' meeting. In addition, the information set forth under the caption "Business—Other Business Matters—Corporate

Governance Matters" in Item1 regarding our Code of Business Conduct is incorporated by reference in response to this Item.

ITEM11. EXECUTIVECOMPENSATION

The information required by this Itemis incorporated by reference to the Company's definitive Proxy Statement in connection with the

2013 annualstockholders' meeting.

ITEM12. SECURITYOWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER

MATTERS

The information required by this Itemis incorporated by reference to the Company's definitive Proxy Statement in connection with the

2013 annualstockholders' meeting.

ITEM13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Itemis incorporated by reference to the Company's definitive Proxy Statement in connection with the

2013 annualstockholders' meeting.

ITEM14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Itemis incorporated by reference to the Company's definitive Proxy Statement in connection with the

2013 annualstockholders' meeting.

PART IV

ITEM15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

A. INDEX

1. ConsolidatedFinancial Statements

See Indexon page 57.

2. Financial Statement Schedules

Financialstatement 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 financialstatements.

113
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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 (Form8-K for January 21, 2010).

3.2 Certificate of Amendment of Restated Certificate of Incorporation, dated as of May 1, 2012

(Form10-Q for the quarter ended June 30, 2012).

3.3 Amended and Restated Bylaws, effective as of February 17, 2012 (Form10-Q for the quarter

ended June 30, 2012).

4.1 Formof 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 (Form8-K for August 30, 2001).

(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form10-Q for

the quarter ended June 30, 2010).

(b) Amendment No. 2 to Note Purchase Agreement, dated as of September 28, 2010 (Form10-

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 (Form8-K for July 16, 2008).

(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form10-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 (Form10-K for 2008).

(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form10-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 (Form10-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 (Form10-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 (Form10-Q for the quarter ended June 30, 2012).
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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 (Form10-Q for the quarter ended

September 30, 2012).
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Table of Contents

Exhibit

Number Description

*10.1 Formof Change in Control Agreement between the Company and Certain Officers (Form10-K

for 2008).

(a) Formof Change in Control Agreement between the Company and Certain Officers

(Confirmation that Certain Benefits no Longer Apply) (Form10-K for 2010).

*10.2 Formof Indemnity Agreement between the Company and Certain Officers.

*10.3 Deferred Compensation Plan of the Company, as Amended and Restated, Effective January 1,

2011 (Form10-Q for the quarter ended June 30, 2011).

*10.4 Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001

(Form10-K for 2001).

(a) Amendment to Employment Agreement between the Company and Dan O. Dinges,

effective December 31, 2008 (Form10-K for 2008).

*10.5 2004 Incentive Plan (Form10-Q for the quarter ended June 30, 2004).

(a) First Amendment to the 2004 Incentive Plan effective February 23, 2007 (Form10-Q for the

quarter ended March 31, 2007).

(b) Second Amendment to the 2004 Incentive Plan Amendment, effective as of December 31,

2008 (Form10-K for 2008).

*10.6 2012 Formof Non-Employee Director Restricted Stock Unit Award Agreement.

*10.7 Forms of Award Agreements for Executive Officers under 2004 Incentive Plan.

(a) 2012 Formof Restricted Stock Award Agreement.

(b) 2012 Formof Stock Appreciation Rights Award Agreement.

(c) 2012 Formof Performance Share Award Agreement (Officers).

(d) 2012 Formof Hybrid Performance Share Award Agreement.

(e) 2012 Formof Performance Share Award Agreement (Employees).

10.8 Cabot Oil & Gas Corporation Mineral, Royalty and Overriding Royalty Interest Plan

(Registration Statement No. 333-135365).

(a) Formof Conveyance of Mineral and/or Royalty Interest (Registration Statement No. 333-

135365).

(b) Formof Conveyance of Overriding Royalty Interest (Registration Statement No. 333-
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135365).

*10.9 Savings Investment Plan of the Company, as amended and restated effective January 1, 2009

(Form10-K for 2009).

(a) First Amendment to the Savings Investment Plan of the Company effective October 1,

2010 (Form10-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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116

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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Table of Contents

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.

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.

117

CABOT OIL & GAS CORPORATION

By: /s/ DAN O. DINGES

Dan O. Dinges

Chairman, President and Chief Executive

Of icer

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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Table of Contents

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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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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

or

(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 fromthe 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.

3

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:
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(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 fromthe 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.

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.

4

17. Relationshipto 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 ]

5

Exhibit 10.7(a)

RESTRICTED STOCKAWARD 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 themin the Plan. In the event there is any

(c)
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inconsistency between the terms of this Agreement and the terms of the Plan, the terms of the Plan shallsupersede 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 fromthe 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 fromthe 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 taxobligations (including FICA) required by the law to be withheld, unless other

arrangements for taxwithholding 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 andDividends. 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 fromthe 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
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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

(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,

2

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 fromsuch 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 fromsuch Business Combination or any employee benefit plan (or related trust) of the Company or such

entity resulting fromsuch Business Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then

outstanding shares of common equity of the entity resulting fromsuch 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

fromsuch 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.

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 fromtime 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.
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(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.

3

(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 nationalsecurities 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 ]

4

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, andTerm.

(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.
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(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 termof 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 andAcceleration. 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).

1

4. Methodof Exercise. The SARs may be exercised fromtime 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 fromtime to time. Such notice shallstate 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 fromthe 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 fractionalshares resulting fromthis 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 fromthe 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 taxwithholding requirements, or the person exercising the SARs may deliver to the Company cash sufficient to satisfy all or a

portion of such taxwithholding 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.
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(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 termof 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 performthe 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 programsponsored 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 of the year the award is granted

in order to vest in the award.

2

(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 termof 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 andNon-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 midstreamactivities or the provision of oilfield

3

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

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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.

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(b) You specifically recognize and affirmthat each of the covenants contained in Paragraphs 7(a)(1) through (3) of

this Agreement is a material and important termof 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 termof 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 termof 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 reformthe 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 claimagainst the Company, whether predicated upon this Agreement or
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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 termof 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

5

“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 fromthe 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 fromsuch 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 fromsuch Business Combination or any employee benefit plan (or related

trust) of the Company or such entity resulting fromsuch Business Combination) beneficially owns, directly or indirectly,

35% or more of, respectively, the then outstanding shares of common equity of the entity resulting fromsuch 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,

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resulting fromsuch Business Combination were members of the Incumbent Board at the time of the execution of the initial
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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 Lawandof 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 allshares 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 counselshall, 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 untilsuch legal counselshall

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. ContinuedEmployment andFuture 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.

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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 taxunder 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 fromtime 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 deemproper. A copy of the Plan in its present formis 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:
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Cabot Oil & Gas Corporation

By: /s/ Scott C. Schroeder

Scott C. Schroeder

Vice President, Chief Financial Officer

& Treasurer

Employee:

[ Participant Name ]

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Exhibit 10.7(c)

CABOT OIL & GAS CORPORATION

PERFORMANCESHAREAWARD 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 themin 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 from0 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 fractionalshares 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 (allsources), averaged over the three year performance period (oil conversion based on

economic rate — oil versus gas); and
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(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 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):

2

(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 midstreamactivities 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;

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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

3

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 computerrelated 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 termof 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 termof 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 termof 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 reformthe 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 claimagainst the Company, whether predicated upon this Agreement or otherwise, is not a

defense to enforcement of this Section 5.

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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:

(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 fromthe 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

(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

5

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 fromsuch 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 fromsuch Business Combination or any employee benefit plan (or related trust) of the

Company or such entity resulting fromsuch Business Combination) beneficially owns, directly or indirectly, 35% or more of,

respectively, the then outstanding shares of common equity of the entity resulting fromsuch 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 fromsuch 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.
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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.

6

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 taxpurposes 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 untilsuch 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

7

Exhibit 10.7(d)

CABOT OIL & GAS CORPORATION

HYBRID PERFORMANCESHAREAWARD 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 ].

This Agreement is expressly subject to the terms and provisions of the Company’s 2004 Incentive Plan (the “Plan”). In the event
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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 themin the Plan.

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 originalschedule 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 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 andNon-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:

(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):

th
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(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 midstreamactivities 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

2

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.

(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 termof this Agreement which has induced the Company to provide for the award

of Hybrid Performance Shares granted hereunder, the disclosure of the Confidential

3

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 termof

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
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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 termof 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 reformthe 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 claimagainst the Company, whether predicated upon this Agreement or otherwise, is not a

defense to enforcement of this Section 5.

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:

(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

4

subsection (I), the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly fromthe 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

(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 fromsuch Business Combination (including, without limitation, an entity that as a result of such transaction owns
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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 fromsuch

Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting fromsuch Business

Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common equity

of the entity resulting fromsuch 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 fromsuch

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.

5

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 taxpurposes 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 untilsuch time as the ownership of such shares of Common Stock has been

transferred to the Employee.

12. Controlling Agreement. This Agreement shallsupersede 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.

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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.

(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

Employee’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 nationalsecurities exchanges as may be required.

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 fromthe application of Section 409A.

(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.

(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.

(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

7

(i) are payable under this Agreement upon the upon the Employee’s “separation fromservice”

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 sixmonths fromthe date of the termination of the

Employee’s employment or (ii) the date of the Employee’s death.
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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 ]

8

Exhibit 10.10

CABOT OIL & GAS CORPORATION

NONEMPLOYEEDIRECTOR DEFERRED COMPENSATION PLAN

(As EstablishedEffective 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 formprovided 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.
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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 fromtime 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 formof 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 formacceptable to the Committee for the purpose of deferring Annual Fees.

Each Eligible Director, by filing an Election at the time and in the formdescribed 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.

2

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
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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. AUTHORITYOF 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 whomthe Committee has delegated authority in accordance with the provisions of this Plan

shall be liable for anything done or omitted to be done by himor 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 fromtime 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.

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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

fromthe 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 claimagainst 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
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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.

4

Exhibit 10.9

CABOT OIL & GAS CORPORATION SAVINGS INVESTMENT PLAN

(As AmendedandRestatedEffective 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 untilsuch 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.
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CABOT OIL & GAS CORPORATION

By:

Title:

Exhibit 10.7(e)

CABOT OIL & GAS CORPORATION

PERFORMANCESHAREAWARD 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.

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 themin 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 from0 to 100% of the Fair Market Value of a share of Common Stock payable in Common Stock

plus from0 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 fractionalshares 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 fromthe 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.
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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 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

2

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

th
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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 midstreamactivities 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

3

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.

(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 termof 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 termof 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 termof Section 5(a) or (B) all or any part of
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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.

4

(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 reformthe 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 claimagainst 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 (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-sumpayment of cash in the amount

equal to the aggregate of the Deemed Share Value for each full and fractionalshare 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 formof a single lump-sumpayment. 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

5

equal to the sumof (1) the aggregate of the Deemed Share Value on the date of the Corporate Event for each full and fractionalshare to

which the Employee is entitled, plus (2) interest compounded monthly fromthe 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 froma source

approved by the Compensation Committee, in its sole discretion), as adjusted fromtime to time.

“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
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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 fromthe 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

(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 fromsuch 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

6

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 fromsuch

Business Combination or any employee benefit plan (or related trust) of the Company or such entity resulting fromsuch Business

Combination) beneficially owns, directly or indirectly, 35% or more of, respectively, the then outstanding shares of common equity

of the entity resulting fromsuch 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 fromsuch

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.

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.
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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 taxpurposes 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 untilsuch time as the ownership of such shares of Common Stock has been transferred to the

Employee.

7

12. This Agreement shallsupersede 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 fromthe 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 fromservice” 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 fromservice

shall be paid on the fifteenth business day next following the earlier of (i) the expiration of sixmonths fromthe date of the termination of the

Employee’s employment or (ii) the date of the Employee’s death.

8

IN WITNESS WHEREOF, the parties hereto cause this Agreement to be executed as of the date hereof.
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CABOT OIL & GAS CORPORATION

/s/ Scott C. Schroeder

By: Scott C. Schroeder

Title: Vice President, Chief Financial Officer

& Treasurer

Employee:

[ Participant Name ]

9

EXHIBIT A

COMPARATOR GROUP

BERRYPETROLEUM COMPANY

CIMAREX ENERGYCOMPANY

CONCHO RESOURCES INC.

EQT CORPORATION

EXCO RESOURCES INC.

NEWFIELD EXPLORATION COMPANY

NOBLE ENERGYINC.

PIONEER NATIONALRESOURCES COMPANY

PLAINS EXPLORATION & PRODUCTION COMPANY

QEP RESOURCES INC.

QUICKSILVER RESOURCES, INC.

RANGERESOURCES CORPORATION

SOUTHWESTERN ENERGYCOMPANY

SM ENERGYCOMPANY

ULTRA PETROLEUM

WPX ENERGY, INC.

10

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 day of December, 2012.

CABOT OIL & GAS CORPORATION

By: /s/ Deidre L. Shearer

st
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Deidre L. Shearer

Corporate Secretary and Managing Counsel

5

EXHIBIT A

Formof 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 PetroleumCanada Corporation

Cabot Oil & Gas Holdings Company

COGFinance 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 ACCOUNTINGFIRM

We hereby consent to the incorporation by reference in the Registration Statements on FormS-3 (File Nos. 333-68350 and 333-83819) and

FormS-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 financialstatements and the effectiveness of internal control over financial reporting, which appears in this

Form10-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2013
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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

Form10-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 FormS-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 firmwhich report and references are to be included in Form10-K for the year ended December 31, 2012 to be filed by

Cabot Oil & Gas Corporation with the Securities and Exchange Commission.

The Form10-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 FirmNo. 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 Form10-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 financialstatements, 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) allsignificant 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 Of icer
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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 Form10-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 financialstatements, 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) allsignificant 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/ SCOTT C. SCHROEDER

Scott C. Schroeder

Vice President and Chief Financial Of icer
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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, UnitedStates 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 Form10-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 Of icer

/s/ SCOTT C. SCHROEDER

Scott C. Schroeder

Chief Financial Of icer
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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 andFuture 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,
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reservoir, or field. Reserves estimates fromvolumetric calculations and fromanalogies 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 wellsite 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 fromcommercialservices 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

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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 fromthose 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 fromthose 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 firmwho 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 FirmNo. 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

3