CABOT OIL & GAS CORP (Form: 10-K, Received: 02/28/2011 15:22:40)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		04-3072771
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		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 x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K x .

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


Large accelerated filer x		Accelerated filer ¨
Non-accelerated filer ¨		Smaller reporting company ¨

(Do not check if a smaller reporting company)

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

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, 2010) was approximately $3.3 billion.

As of February 18, 2011, there were 104,277,128 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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

TABLE OF CONTENTS


PART I		PAGE
ITEM 1	Business		4

ITEM 1A	Risk Factors		20

ITEM 1B	Unresolved Staff Comments		28

ITEM 2	Properties		28

ITEM 3	Legal Proceedings		28

	Executive Officers of the Registrant		30

PART II

ITEM 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		31

ITEM 6	Selected Financial Data		33

ITEM 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations		33

ITEM 7A	Quantitative and Qualitative Disclosures about Market Risk		51

ITEM 8	Financial Statements and Supplementary Data		54

ITEM 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		111

ITEM 9A	Controls and Procedures		111

ITEM 9B	Other Information		111

PART III

ITEM 10	Directors, Executive Officers and Corporate Governance		112

ITEM 11	Executive Compensation		112

ITEM 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		112

ITEM 13	Certain Relationships and Related Transactions, and Director Independence		112

ITEM 14	Principal Accountant Fees and Services		112

PART IV

ITEM 15	Exhibits and Financial Statement Schedules		112

The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. These statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives and other factors detailed in this document and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and uncertainties. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual outcomes may vary materially from those included in this document. See “Forward-Looking Information” for further details.

GLOSSARY OF CERTAIN OIL AND GAS TERMS

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

Abbreviations

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

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet of natural gas equivalent.

Mbbls. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet of natural gas equivalent.

Mmbtu. One million British thermal units.

Mmcf . One million cubic feet of natural gas.

Mmcfe . One million cubic feet of natural gas equivalent.

NGL. Natural gas liquids.

NYMEX. New York Mercantile Exchange.

Definitions

Developed reserves. Developed reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

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

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

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

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

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

Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geological barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological 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 and/or production of an oil or gas well or lease.

Proved reserves. Proved reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions and operating methods prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Recompletion. An operation whereby a completion in one zone is abandoned in order to attempt a completion in a different zone within the existing wellbore.

Reservoir . A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure. The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of future price changes to the extent

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provided by contractual arrangements in existence at year-end), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on year-end costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the appropriate year-end statutory federal and state income tax rate with consideration of future tax rates already legislated, to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and gas reserves.

Undeveloped reserves. Undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

The terms “developed reserves”, “development well”, “exploratory well”, “extension well”, “field”, “proved reserves”, “reserves”, “reservoir” and “undeveloped reserves” are defined by the SEC.

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PART I

ITEM 1.

BUSINESS

OVERVIEW

Cabot Oil & Gas Corporation is an independent oil and gas company engaged in the development, exploitation and exploration of oil and gas properties located in the United States. In 2009, we restructured our operations by combining our Rocky Mountain and Appalachian areas to form the North region and combining the Anadarko Basin with our Texas and Louisiana areas to form the South region. Certain prior period amounts and historical descriptions have been reclassified to reflect this reorganization. Operationally, we now have two primary regional offices located in Houston, Texas and Pittsburgh, Pennsylvania.

In 2010, natural gas prices decreased from the price levels experienced during 2009, while crude oil prices increased. Our 2010 average realized natural gas price was $5.54 per Mcf, 26% lower than the 2009 average realized price of $7.47 per Mcf. Our 2010 average realized crude oil price was $97.91 per Bbl, 14% higher than the 2009 average realized price of $85.52 per Bbl. These realized prices include realized gains and losses resulting from commodity derivatives. For information about the impact of these derivatives on realized prices, refer to the “Results of Operations” section in Item 7 of this Annual Report on Form 10-K.

In 2010, our investment program totaled $891.5 million, including lease acquisition ($130.7 million) and drilling and facilities ($654.2 million) programs. Our capital spending was funded through cash on hand, operating cash flow, borrowings on our revolving credit facility, proceeds from our new senior notes offering and select asset sales.

We remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure sufficient liquidity, including cash resources and available credit. We believe these strategies are appropriate for our portfolio of projects and the current industry environment and will continue to add shareholder value over the long-term.

In December 2010, we sold our existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations to Williams Field Services (Williams), a subsidiary of Williams Partners L.P., for $150 million and recognized a $49.3 million gain on sale of assets. Under the terms of the purchase and sale agreement, we are obligated to construct pipelines to connect certain of our 2010 program wells, complete the construction of the Lathrop compressor station and complete taps into certain pipeline delivery points. We expect to complete these obligations in the first half of 2011. We also entered into a 25-year firm gathering contract with Williams that requires Williams to complete construction of approximately 32 miles of high pressure pipeline, 65 miles of trunklines in Susquehanna County, and build two compressor stations in the next two years. Additionally, Williams will connect all of our drilling program wells, which will connect our production to five interstate pipeline delivery options.

In addition, in December 2010 we closed a private placement of $175 million principal amount of senior unsecured fixed rate notes with a weighted-average interest rate of 5.58%.

In September 2010, we amended and restated our revolving credit facility to increase the available credit line to $900 million and with an accordion feature allowing us to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. The amended facility provides for a $1.5 billion borrowing base and extends the term of the agreement to September 2015.

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In April 2009, we sold substantially all of our Canadian properties to Tourmaline Oil Corporation (Tourmaline) in exchange for cash and common stock shares of Tourmaline. In November 2010, we sold our investment in Tourmaline for $61.3 million and recognized a $40.7 million gain on sale of assets.

In 2010, we sold various other properties for total proceeds of $30.4 million and an aggregate gain of $15.3 million.

In August 2008, we completed the acquisition of producing properties, leasehold acreage and a natural gas gathering infrastructure in east Texas (the “east Texas acquisition”). We paid total net cash consideration of approximately $604.0 million. In order to finance the east Texas acquisition, we completed a public offering of 5,002,500 shares of our common stock in June 2008, receiving net proceeds of $313.5 million, and we closed a private placement in July 2008 of $425 million principal amount of 6.51% weighted average senior unsecured fixed rate notes.

On an equivalent basis, our production level in 2010 increased by 27% from 2009. We produced 130.6 Bcfe, or 357.9 Mmcfe per day, in 2010, as compared to 103.0 Bcfe, or 282.1 Mmcfe per day, in 2009. Natural gas production increased to 125.5 Bcf in 2010 from 97.9 Bcf in 2009, primarily due to increased production in the North region associated with the increased drilling program and the Lathrop compressor station in Susquehanna County, Pennsylvania. The decline in the other areas is related to natural production decline. Oil production decreased by 10 Mbbls from 818 Mbbls in 2009 to 808 Mbbls in 2010 due primarily to a decrease in production in the North and a decrease in production in Canada due to the sale of our Canadian properties in April 2009, partially offset by increased production in the South region associated with the Eagle Ford shale and Pettet formation production.

For the year ended December 31, 2010, we drilled 113 gross wells (87.1 net) with a success rate of 98% compared to 143 gross wells (118.6 net) with a success rate of 95% for the prior year. In 2011, we plan to drill approximately 110 gross wells (83.1 net), focusing our capital program in the Marcellus shale in northeast Pennsylvania and the Eagle Ford shale in south Texas.

Our 2010 total capital and exploration spending was $891.5 million compared to $640.4 million in 2009. In both 2010 and 2009, we allocated our planned program for capital and exploration expenditures among our various operating regions based on return expectations, availability of services and human resources. We plan to continue such method of allocation in 2011. Funding of the program is expected to be provided by operating cash flow, existing cash and, if required, borrowings under our credit facility. For 2011, the North region is expected to receive approximately 58% of the anticipated capital program, with the remaining 42% dedicated to the South region. In 2011, we plan to spend approximately $600 million on capital and exploration activities.

Our proved reserves totaled approximately 2,701 Bcfe at December 31, 2010, of which 98% were natural gas. This reserve level was up by 31% from 2,060 Bcfe at December 31, 2009 on the strength of results from our drilling program. In 2010, we had a net upward revision of 136.7 Bcfe, which was primarily due to an upward performance revision of 284.4 Bcfe, primarily in the Dimock field in northeast Pennsylvania, and an upward revision of 35.0 Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of 182.7 Bcfe (115.1 Bcfe in the North region and 67.6 Bcfe in the South region) of proved undeveloped reserves that are no longer in our five-year development plan.

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The following table presents certain reserve, production and well information as of December 31, 2010.


	North			South			Total
Proved Reserves at Year End (Bcfe)
Developed.		1,251.3			472.9			1,724.2
Undeveloped		755.9			221.0			976.9

Total		2,007.2			693.9			2,701.1
Average Daily Production (Mmcfe per day)		223.5			134.4			357.9
Reserve Life Index (In years) ⁽¹⁾		24.6			14.1			20.7
Gross Wells		4,185			1,769			5,954
Net Wells ⁽²⁾		3,588.5			1,231.1			4,819.6
Percent Wells Operated (Gross)		89.0	%		76.0	%		85.1	%

⁽¹⁾	Reserve Life Index is equal to year-end reserves divided by annual production.

⁽²⁾	The term “net” as used in “net acreage” or “net production” throughout this document refers to amounts that include only acreage or production that is owned by us and produced to our interest, less royalties and production due others. “Net wells” represents our working interest share of each well.

Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right, in general, to develop oil and/or natural gas on the properties. Their primary terms range in length from approximately three to ten years. These properties are held for longer periods if production is established. We own leasehold rights on approximately 2.3 million gross acres. In addition, we own fee interest in approximately 0.2 million gross acres, primarily in West Virginia. Our largest field (Dimock), which is our only field that contains more than 15% of our proved reserves, is located in northeast Pennsylvania. This field makes up approximately 46% of our proved reserves.

The following table presents certain information with respect to our Dimock field:


	Year Ended December 31,
	2010		2009		2008
Production:
Natural gas (Bcf)		49.5		36.3		0.6
Crude oil and condensate (Mbbls)		—		—		—
Produced Sales Price: ⁽¹⁾
Natural gas ($/Mcf)	$	4.48	$	4.19	$	7.28
Crude oil and condensate ($/Bbl)	$	—	$	—	$	—
Production Cost ($/Mcfe):	$	0.08	$	0.03	$	0.01

⁽¹⁾	Excludes realized impact of derivative instruments.

NORTH REGION

The North region is comprised of the Appalachian and Rocky Mountains areas. Our activities in the Appalachian area are concentrated primarily in northeast Pennsylvania and in West Virginia. Our activities in the Rocky Mountains area are concentrated in the Green River and Washakie Basins in Wyoming. This region is managed from our office in Pittsburgh, Pennsylvania. In this region, our assets include a large acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity. In December 2010, we sold our existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations. In July 2010, we sold our properties in the Paradox Basin in Colorado.

Capital and exploration expenditures for 2010 were $603.6 million, or 68% of our total 2010 capital and exploration expenditures, compared to $380.3 million for 2009, or 60% of our total 2009 capital and exploration

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expenditures. This increase in spending was substantially driven by an expanded Marcellus horizontal drilling program in northeast Pennsylvania to hold acreage. For 2011, we have budgeted approximately $350.0 million for capital and exploration expenditures in the region.

At December 31, 2010, we had 4,185 wells (3,588.5 net), of which 3,724 wells are operated by us. There are multiple producing intervals in the Appalachian area that includes the Big Lime, Weir, Berea and Devonian (including Marcellus) shale formations at depths primarily ranging from 950 to 7,800 feet, with an average depth of approximately 4,050 feet. In the Rocky Mountains area, principal producing intervals are in the Almond, Frontier and Dakota formations at depths ranging from 8,100 to 14,375 feet, with an average depth of approximately 11,050 feet.

Natural gas production and reserves in the North region are primarily associated with the Marcellus shale. At December 31, 2010, we had 2,007.2 Bcfe of proved reserves (substantially all natural gas) in the North region, constituting 74% of our total proved reserves. Developed and undeveloped reserves made up 1,251.3 Bcfe and 755.9 Bcfe of the total proved reserves for the North region, respectively.

In 2010, we drilled 63 wells (61.3 net) in the North region, of which 62 wells (60.3 net) were development and extension wells. In 2011, we plan to drill approximately 54 wells (54.0 net), primarily in the Dimock field in northeast Pennsylvania.

In 2010, we produced and marketed approximately 221.8 Mmcf per day of natural gas and 272.5 barrels of crude oil/condensate/NGL per day in the North region at market responsive prices. Average daily production in 2010 was 223.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2010 was 81.0 Bcf and 100 Mbbls, respectively.

Ancillary to our exploration, development and production operations, we operated a number of gas gathering and transmission pipeline systems, made up of approximately 3,148 miles of pipeline with interconnects to three interstate transmission systems and seven local distribution companies and numerous end users as of the end of 2010. The majority of our pipeline infrastructure in West Virginia is regulated by the Federal Energy Regulatory Commission (FERC) for interstate transportation service and the West Virginia Public Service Commission (WVPSC) for intrastate transportation service. As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC and the WVPSC. Our natural gas gathering and transmission pipeline systems in West Virginia enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system.

We have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas and the higher prices typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The storage fields also enable us to increase for shorter intervals of time the volume of natural gas that we can deliver by more than 40% above the volume that we could deliver solely from our production in the North region. The pipeline systems and storage fields are fully integrated with our operations.

The principal markets for our North region natural gas are in the northeastern and northwestern United States. We sell natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system. Approximately 42% of our natural gas sales volume in the North region is sold at index-based prices under contracts with terms of one year or greater. The remaining 58% of our natural gas sales volume is sold under contracts with terms less than one year. Spot market sales are made at index-based prices under month-to-month contracts, while industrial and utility sales generally are made under year-to-year contracts.

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SOUTH REGION

Our development, exploitation, exploration and production activities in the South region are primarily concentrated in east and south Texas and Oklahoma. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley, Haynesville, Bossier, and James Lime formations in east Texas, the Eagle Ford, Frio, Vicksburg and Wilcox formations in south Texas and the Chase, Morrow and Chester formations in the Anadarko Basin in Oklahoma at measured depths ranging from approximately 2,500 to 17,700 feet, with an average depth of approximately 8,950 feet. We sold our Woodford shale prospect located in Oklahoma in June 2010 and certain oil and gas properties in the Texas panhandle in November 2010.

Capital and exploration expenditures were $280.4 million for 2010, or 32% of our total 2010 capital and exploration expenditures, compared to $237.6 million for 2009, or 37% of our total 2009 capital and exploration expenditures. This increase in capital spending is primarily due to lease acquisitions to establish a greater position in the oil window of the Eagle Ford shale. For 2011, we have budgeted approximately $250 million for capital and exploration expenditures in the region. Our 2011 South region drilling program will emphasize activity primarily in the Eagle Ford shale in south Texas.

We had 1,769 wells (1,231.1 net) in the South region as of December 31, 2010, of which 1,345 wells are operated by us. Average daily production in 2010 was 134.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2010 was 44.5 Bcf and 759 Mbbls, respectively.

At December 31, 2010, we had 693.9 Bcfe of proved reserves (93% natural gas) in the South region, which represented 26% of our total proved reserves. Developed and undeveloped reserves made up 472.9 Bcfe and 221.0 Bcfe of the total proved reserves for the South region, respectively.

In 2010, we drilled 50 wells (25.8 net) in the South region, of which 47 wells (23.3 net) were development and extension wells. In 2011, we plan to drill 56 wells (29.1 net), primarily in the Eagle Ford shale in south Texas.

Our principal markets for the South region natural gas are in the industrialized Gulf Coast area and the Midwestern United States. We sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Currently, approximately 83% of our natural gas sales volumes in the South region are sold at index-based prices under contracts with terms of one year or greater. The remaining 17% of our natural gas sales volumes are sold at index-based prices under short-term agreements. The South region properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.

In 2010, we produced and marketed approximately 122.0 Mmcf per day of natural gas and 2,079.1 barrels of crude oil/condensate/NGL per day in the South region at market responsive prices. Average daily production in 2010 was 134.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2010 was 44.5 Bcf and 759 Mbbls, respectively.

RISK MANAGEMENT

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 2010 we employed natural gas and crude oil swap agreements for portions of our 2010 production to attempt to manage price risk more effectively. During 2010, we also entered into crude oil swaps to hedge our price exposure on our 2010 production, natural gas swaps to hedge our price exposure on our 2011 production and crude oil price collars to hedge our price exposure on our 2011 production. In addition, we also have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting. In 2009 and 2008, we employed price collars and swaps to hedge our price exposure on our production.

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The collar arrangements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of natural gas or crude oil for the period is greater or less than the fixed price established for that period when the swap is put in place.

For 2010, swaps covered 29% of natural gas production and 90% of crude oil production and had a weighted-average price of $9.30 per Mcf and $104.25 per Bbl, respectively.

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


Commodity and Derivative Type	Weighted-Average Contract Price	Volume		Contract Period
Derivatives Designated as Hedging Instruments
Natural Gas Swaps	$6.24 per Mcf		12,909 Mmcf		January - December 2011
Crude Oil Collars	$93.25 Ceiling /$80.00 Floor per Bbl		365 Mbbl		January - December 2011
Derivatives Not Designated as Hedging Instruments
Natural Gas Basis Swaps	$(0.27) per Mcf		16,123 Mmcf		January - December 2012

We will continue to evaluate the benefit of employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk” for further discussion concerning our use of derivatives.

RESERVES

Current Reserves

The following table presents our estimated proved reserves at December 31, 2010.


	Natural Gas *(Mmcf)*		Liquids ⁽¹⁾ *(Mbbl)*		Total ⁽²⁾ *(Mmcfe)*
Developed:
North		1,243,051		1,373		1,251,289
South		438,400		5,756		472,936
Undeveloped:
North		755,767		22		755,899
South		206,940		2,340		220,978

Total		2,644,158		9,491		2,701,102

⁽¹⁾	Liquids include crude oil, condensate and natural gas liquids.

⁽²⁾	Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.

Our reserve estimates were based on decline curve extrapolations, material balance calculations, analogies, or combinations of these methods for each well.

The proved reserve estimates presented herein were prepared by our petroleum engineering staff and audited by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents made independent estimates for 100% of the proved reserves estimated by us and concluded the following: In their judgment we have an effective system for gathering data and documenting information required to estimate our proved reserves and

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project our future revenues. 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. For additional information regarding estimates of proved reserves, the audit of such estimates by Miller and Lents, Ltd., and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. A copy of the audit letter by Miller and Lents, Ltd., dated February 1, 2011, has been filed as an exhibit to this Form 10-K. Our reserves are sensitive to natural gas and crude oil sales prices and their effect on the economic productive life of producing properties. Our reserves are based on 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during 2010. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in prices may result in negative impacts of this nature.

Internal Control

Our corporate reservoir engineers report to the Director of Engineering, who maintains oversight and compliance responsibility for the internal reserve estimation process and provides oversight for the annual audit of our year-end reserves by our independent third party engineers, Miller and Lents, Ltd. Our corporate reservoir engineering group consists of two petroleum/chemical engineers, with petroleum/chemical engineering degrees and between 11 and 28 years of industry experience, between four and 28 years of reservoir engineering/management experience, and between three and 12 years managing our reserves. Both are members of the Society of Petroleum Engineers.

Qualifications of Third Party Engineers

The technical person primarily responsible for audit of our reserve estimates at Miller and Lents, Ltd. meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents, Ltd. is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

For additional information about the risks inherent in our estimates of proved reserves, see “Risk Factors—Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.

Proved Undeveloped Reserves

At December 31, 2010, we had 976.9 Bcfe of proved undeveloped reserves, which represents an increase of 241.7 Bcfe compared with December 31, 2009. For 2010, total capital related to the development of proved undeveloped reserves was $183.4 million, resulting in the conversion of 216.9 Bcfe of reserves to proved developed. During 2010, we had 391.8 Bcfe of proved undeveloped reserve additions and 249.5 Bcfe of positive proved undeveloped reserve performance revisions, primarily in the Dimock field in northeast Pennsylvania. Lastly, we removed 182.7 Bcfe (115.1 Bcfe in the North region and 67.6 Bcfe in the South region) of proved undeveloped reserves associated with drilling locations no longer anticipated to be developed within the next five years.

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Historical Reserves

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


	Natural Gas *(Mmcf)*			Oil & Liquids *(Mbbl)*			Total *(Mmcfe) ⁽¹⁾*
December 31, 2007 ⁽⁵⁾		1,559,953			9,328			1,615,919

Revision of Prior Estimates ⁽²⁾		(47,745	)		(1,593	)		(57,302	)
Extensions, Discoveries and Other Additions		297,089			1,134			303,895
Production.		(90,425	)		(794	)		(95,191	)
Purchases of Reserves in Place		167,262			1,268			174,872
Sales of Reserves in Place		(141	)		(2	)		(156	)

December 31, 2008 ⁽⁵⁾		1,885,993			9,341			1,942,037

Revision of Prior Estimates ⁽³⁾		(193,767	)		(1,062	)		(200,143	)
Extensions, Discoveries and Other Additions		459,612			544			462,880
Production		(97,914	)		(844	)		(102,976	)
Purchases of Reserves in Place		9			—			9
Sales of Reserves in Place		(40,771	)		(196	)		(41,949	)

December 31, 2009		2,013,162			7,783			2,059,858

Revision of Prior Estimates ⁽⁴⁾		139,016			(379	)		136,742
Extensions, Discoveries and Other Additions		632,980			2,944			650,644
Production		(125,474	)		(858	)		(130,622	)
Purchases of Reserves in Place		593			4			617
Sales of Reserves in Place		(16,119	)		(3	)		(16,137	)

December 31, 2010		2,644,158			9,491			2,701,102


Proved Developed Reserves
December 31, 2007		1,133,937			7,026			1,176,091
December 31, 2008		1,308,155			6,728			1,348,521
December 31, 2009		1,288,169			6,082			1,324,663
December 31, 2010		1,681,451			7,129			1,724,225

Proved Undeveloped Reserves
December 31, 2007		426,016			2,302			439,828
December 31, 2008		577,838			2,613			593,516
December 31, 2009		724,993			1,701			735,199
December 31, 2010		962,707			2,362			976,877

⁽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 majority of the revisions were the result of the decrease in the natural gas price.

⁽³⁾

The net downward revision of 200.1 Bcfe was primarily due to (i) downward revisions of 101.6 Bcfe due to lower 2009 oil and natural gas prices compared to 2008 and (ii) downward revisions of 120.4 Bcfe due to the removal of proved undeveloped reserves scheduled for development beyond five years primarily due to the application of the SEC’s oil and gas reserve calculation methodology effective beginning in 2009, partially offset by 21.9 Bcfe of positive performance revisions.

⁽⁴⁾

The net upward revision of 136.7 Bcfe was primarily due to (i) an upward performance revision of 284.4 Bcfe, primarily in the Dimock field in northeast Pennsylvania, and (ii) an upward revision of 35.0 Bcfe associated with increased reserve commodity pricing partially offset by a downward revision of 182.7 Bcfe of proved undeveloped reserves that are no longer in our five-year development plan.

⁽⁵⁾	Prior to 2009, reserve estimates were based on year end prices.

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Production and Sales

The following table presents regional historical information about our net wellhead sales volume for natural gas and crude oil (including condensate and natural gas liquids), produced natural gas and crude oil realized sales prices, and production costs per equivalent.


	Year Ended December 31,
	2010		2009		2008
Net Wellhead Sales Volume
Natural Gas (Bcf)
North		81.0		48.2		39.7
South		44.5		48.8		46.6
Canada ⁽³⁾		—		1.0		4.1
Crude/Condensate/Ngl (Mbbl)
North		100		118		118
South		759		720		655
Canada ⁽³⁾		—		7		21
Equivalents (Bcfe)
North		81.6		48.9		40.4
South		49.1		53.1		50.5
Canada ⁽³⁾		—		1.0		4.3
Produced Natural Gas Sales Price *($/Mcf)* ⁽¹⁾
North	$	4.59	$	6.59	$	7.95
South		7.26		8.42		8.84
Canada ⁽³⁾		—		3.72		7.62
Weighted-Average		5.54		7.47		8.39
Produced Crude/Condensate Sales Price *($/Bbl)* ⁽¹⁾
North	$	69.31	$	54.11	$	93.62
South		101.65		90.86		88.46
Canada ⁽³⁾		—		33.97		85.08
Weighted-Average		97.91		85.52		89.11
Production Costs *($/Mcfe)* ⁽²⁾
North	$	0.45	$	0.67	$	0.80
South		0.93		0.78		0.76
Canada ⁽³⁾		—		1.55		0.88
Weighted-Average		0.63		0.74		0.78

⁽¹⁾	Represents the average realized sales price for all production volumes and royalty volumes sold during the periods shown, net of related costs (principally purchased gas royalty, transportation and storage). Includes realized impact of derivative instruments.

⁽²⁾

Production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), the costs of administration of production offices and insurance, but is exclusive of depreciation and depletion applicable to capitalized lease acquisition, exploration and development expenditures and taxes other than income.

⁽³⁾	In April 2009, we sold substantially all of our Canadian properties.

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Acreage

The following tables summarize our gross and net developed and undeveloped leasehold and mineral fee acreage by region at December 31, 2010. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.


	Developed				Undeveloped				Total
	Gross		Net		Gross		Net		Gross		Net
*Leasehold Acreage*
North		887,288		731,211		763,389		612,178		1,650,677		1,343,389
South		389,905		290,436		274,800		205,893		664,705		496,329

Total		1,277,193		1,021,647		1,038,189		818,071		2,315,382		1,839,718

*Mineral Fee Acreage*
North		116,674		97,992		62,651		51,819		179,325		149,811
South		16,947		14,242		1,892		690		18,839		14,932

Total		133,621		112,234		64,543		52,509		198,164		164,743

Aggregate Total		1,410,814		1,133,881		1,102,732		870,580		2,513,546		2,004,461

Total Net Undeveloped Acreage Expiration

The following table presents our net undeveloped acreage expiring over the next three years by region as of December 31, 2010. The figures below assume no future successful development or renewal of undeveloped acreage.


	2011		2012		2013
North		142,999		121,146		160,554
South		89,528		39,621		36,768

Total		232,527		160,767		197,322

Well Summary

The following table presents our ownership in productive natural gas and oil wells by region at December 31, 2010. This summary includes natural gas and oil wells in which we have a working interest.


	Natural Gas				Oil				Total ⁽¹⁾
	Gross		Net		Gross		Net		Gross		Net
North		4,130		3,552.4		36		18.1		4,166		3,570.5
South		1,571		1,060.4		162		136.4		1,733		1,196.8

Total		5,701		4,612.8		198		154.5		5,899		4,767.3

⁽¹⁾	Total excludes 55 (52.3 net) service wells.

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Drilling Activity

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


	Year Ended December 31, 2010
	North				South				Total
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		57		55.3		39		19.0		96		74.3
Dry		—		—		1		1.0		1		1.0
Extension Wells
Productive		5		5.0		7		3.3		12		8.3
Dry		—		—		—		—		—		—
Exploratory Wells
Productive		—		—		3		2.5		3		2.5
Dry		1		1.0		—		—		1		1.0

Total		63		61.3		50		25.8		113		87.1

Wells Acquired		—		—		—		—		—		—
Wells in Progress at End of Year		7		6.0		7		4.2		14		10.3

	Year Ended December 31, 2009 ⁽¹⁾
	North				South				Total
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		53		51.3		71		52.3		124		103.6
Dry		1		1.0		4		3.0		5		4.0
Extension Wells
Productive		7		7.0		—		—		7		7.0
Dry		—		—		—		—		—		—
Exploratory Wells
Productive		1		0.1		4		2.4		5		2.5
Dry		—		—		2		1.5		2		1.5

Total		62		59.4		81		59.2		143		118.6

Wells Acquired		—		—		1		1.0		1		1.0

⁽¹⁾	In April 2009, we sold substantially all of our Canadian properties.


	Year Ended December 31, 2008
	North				South				Canada				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		250		227.2		145		99.7		3		2.0		398		328.9
Dry		1		1.0		7		6.3		1		0.6		9		7.9
Extension Wells
Productive		3		3.0		2		1.7		—		—		5		4.7
Dry		1		1.0		—		—		—		—		1		1.0
Exploratory Wells
Productive		3		3.0		11		6.8		2		0.8		16		10.6
Dry		3		1.5		—		—		—		—		3		1.5

Total		261		236.7		165		114.5		6		3.4		432		354.6

Wells Acquired		—		—		70		68.3		—		—		70		68.3

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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 in the North region our extensive acreage position, existing natural gas gathering and pipeline systems in West Virginia, services and equipment that we have secured for the upcoming years and storage fields in West Virginia 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 substantially larger financial and other resources.

OTHER BUSINESS MATTERS

Major Customer

In 2010, one customer accounted for approximately 11%, of the Company’s total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively, of the Company’s total sales. In 2008, one customer accounted for approximately 16% of the Company’s total sales.

Seasonality

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

Regulation of Oil and Natural Gas Exploration and Production

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil 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 FERC regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC has granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of gas for resale without further FERC approvals. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the

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provisions of the Energy Policy Act of 2005 (2005 Act), the NGA has been 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 new regulations that are intended to increase natural gas pricing transparency through, among other things, requiring market participants to report their gas sales transactions annually to the FERC, and new regulations that require certain non-interstate pipelines to post daily scheduled volume information and design capacity for certain points on their systems. The 2005 Act also significantly increased the penalties for violations of the NGA and the FERC’s regulations. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties in an effort to add greater fairness, consistency and transparency to its enforcement program.

Our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation, because the prices we receive for our production are affected by the cost of transporting the gas to the consuming market. Through a series of comprehensive rulemakings, 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 regulatory changes 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, transforming the role of interstate pipeline companies from wholesale marketers of gas to the primary role of gas transporters, 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 gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants, and most pipelines have also implemented the large-scale divestiture of their gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines thus now generally 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. Sellers and buyers of gas have gained direct access to the particular pipeline services they need, 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.

Certain of our pipeline systems and storage fields in West Virginia are regulated for safety compliance by the U.S. Department of Transportation (DOT) and the West Virginia Public Service Commission. In 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (2002 Act), which contains a number of provisions intended to increase pipeline operating safety. The DOT’s final regulations implementing the act became effective February 2004. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission and non-rural gathering pipeline facilities within the next 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 for our pipeline system in West Virginia are 95% completed. Clarification from the DOT published in 2009 brought to light the need for further baseline assessments of cased pipeline crossings covered under our integrity management program. With this exception, reassessment of our West Virginia pipeline system is scheduled to start in 2013 based on the 7 year reassessment requirement. We have completed 100% of the required initial inspection (baseline assessment) under our integrity management program of our pipeline systems in West Virginia. In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which reauthorized the programs adopted under the 2002 Act, proposed enhancements for state programs to reduce excavation damage to pipelines, established increased federal enforcement of one-call excavation programs, and established a new program for review of pipeline security plans and critical facility inspections.

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On December 3, 2009, the DOT adopted a regulation requiring gas and hazardous liquid pipelines that use supervisory control and data acquisition (SCADA) systems and have at least one controller and control room to develop written control room management procedures by August 1, 2011 and implement the procedures by February 1, 2013. In a Proposed Rulemaking issued September 17, 2010, the DOT proposed to expedite the program implementation deadline to August 1, 2011 for most of the requirements, except for certain provisions regarding adequate information and alarm management, which would have a program implementation deadline of August 1, 2012. On November 26, 2010, the DOT updated its reporting requirements for natural gas and hazardous liquid pipelines to be effective January 1, 2011.

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, it is impossible to 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. Similarly, and despite the recent trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, cannot be predicted.

Federal Regulation of Petroleum

Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2010, to implement this required five-year re-determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 2.65 percent should be the oil pricing index for the five-year period beginning July 1, 2011. Another FERC matter that may impact our transportation costs relates to a policy that allows a pipeline structured as a master limited partnership or similar non-corporate entity to include in its rates a tax allowance with respect to income for which there is an “actual or potential income tax liability,” to be determined on a case by case basis. Generally speaking, where the holder of a partnership unit interest is required to file a tax return that includes partnership income or loss, such unit-holder is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. We currently do not transport any of our oil or natural gas liquids on a pipeline structured as a master limited partnership.

We are not able to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or of the application of the FERC’s policy on income tax allowances.

Environmental 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 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 gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us.

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

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

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

Superfund . The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, imposes 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 owner and operator of a site and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.

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

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

Clean Air Act . Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally

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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.

Hydraulic Fracturing. Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs. However, bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including but not limited to 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, both the State of Pennsylvania and certain local governments in that state have adopted a variety of regulations limiting how and where fracturing can be performed. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

Greenhouse Gas. In response to recent studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to warming of the Earth’s atmosphere, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases from sources within the United States between 2012 and 2050. For example, the 110th session of Congress considered various bills that proposed a “cap and trade” scheme of regulation of greenhouse gas emissions that generally would ban emissions above a defined reducing annual cap. Covered parties would be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. In addition, at least 17 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. Most of these cap and trade programs require either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved.

Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of oil or natural gas we produce. Although we would not be impacted to a greater degree than other similarly situated producers of oil and gas, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and gas we produce.

Also, in the wake of the U.S. Supreme Court’s decision in April 2007 in Massachusetts v. Environmental Protection Agency , the EPA has begun to regulate carbon dioxide and other greenhouse gas emissions, even though Congress has yet to adopt new legislation specifically addressing emissions of greenhouse gases. In late 2009, the EPA issued a “Mandatory Reporting of Greenhouse Gases” final rule, which was amended in

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December 2010, establishing a new comprehensive regulation and reporting scheme for operators of stationary sources emitting certain levels of greenhouse gases, and a Final Rule finding that certain current and projected levels of greenhouse gases in the atmosphere threaten public health and welfare of current and future generations. Most recently, in late 2010, the EPA finalized new greenhouse gas reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA’s greenhouse gas reporting rule. Please read “Item 1A. Risk Factors—Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for oil and gas.”

Employees

As of December 31, 2010, we had 409 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement.

Website Access to Company Reports

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

Corporate Governance Matters

The Company’s Corporate Governance Guidelines, Corporate Bylaws, Code of Business Conduct, Corporate Governance and Nominations Committee Charter, Compensation Committee Charter and Audit Committee Charter are available on the Company’s website at www.cabotog.com , under the “Governance” section of “Investor Info.” Requests can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas, 77024.

ITEM 1A.

RISK FACTORS

Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to 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. Natural gas prices have increased from an average price of $3.99 per Mmbtu in 2009 to an average price of $4.39 per Mmbtu in 2010. Oil prices have increased from an average price of $61.80 per barrel in 2009 to an average price of $77.32 per barrel in 2010. Depressed prices in the future would have a negative impact on our future financial results. Because our reserves are predominantly natural gas, changes in natural gas prices have a particularly large 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:

•

the level of consumer product demand;

•

weather conditions;

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•

political conditions in natural gas and oil producing regions, including the Middle East;

•

the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

•

the price of foreign imports;

•

actions of governmental authorities;

•

pipeline availability and capacity constraints;

•

inventory storage levels;

•

domestic and foreign governmental regulations;

•

the price, availability and acceptance of alternative fuels; and

•

overall economic conditions.

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;

•

compliance with governmental requirements; and

•

shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.

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

•

the results of exploration efforts and the acquisition, review and analysis of the seismic data;

•

the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

•

the approval of the prospects by other participants after additional data has been compiled;

•

economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews;

•

our financial resources and results; and

•

the availability of leases and permits on reasonable terms for the prospects.

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

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

You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas and oil reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the Financial Accounting Standards Board (FASB) in Accounting Standards Codification 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general.

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

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

Our reserve report estimates that production from our proved developed producing reserves as of December 31, 2010 will increase at an estimated rate of 30% during 2011 and then decline at estimated rates of 22%, 22% and 15% during 2012, 2013 and 2014, respectively. Future development of proved undeveloped and other reserves currently not classified as proved developed producing will impact these rates of decline. Because of higher initial decline rates from newly developed reserves, we consider this pattern fairly typical.

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

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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 exploration potential, future natural gas and oil prices, operating costs, and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise. We may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. Often, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. If an acquired property is not performing as originally estimated, we may have an impairment which could have a material adverse effect on our financial position and results of operations.

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

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

•

the challenge of integrating the acquired properties while carrying on the ongoing operations of our business; and

•

the possibility of faulty assumptions underlying our expectations.

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

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

Our business involves a variety of operating risks, including:

•

well site blowouts, cratering and explosions;

•

equipment failures;

•

uncontrolled flows of natural gas, oil or well fluids;

•

fires;

•

formations with abnormal pressures;

•

pollution and other environmental risks; 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, impairment of our operations and substantial losses to us.

Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these

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risks. As of December 31, 2010, we owned or operated approximately 3,150 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.

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

Bills have recently been introduced in Congress that would subject hydraulic fracturing to federal regulation under the Safe Drinking Water Act. If adopted, these bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Moreover, the bills introduced in Congress would require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids, many of which are proprietary to the service companies that perform the hydraulic fracturing operations. Such disclosure could make it easier for third parties to initiate litigation against us in the event of perceived problems with drinking water wells in the vicinity of an oil or gas well or other alleged environmental problems. In addition to these federal legislative proposals, some states and 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, both the State of Pennsylvania and certain local governments in that state have adopted a variety of regulations limiting how and where fracturing can be performed. If these types of conditions are adopted, we could be subject to increased costs and possibly limits on the productivity of certain wells.

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 14.9% of our total owned gross wells, or approximately 4.6% of our owned net wells, as of December 31, 2010. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

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

The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Future acts of terrorism 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.

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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. Our failure to obtain these services on acceptable terms could materially harm our business.

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

Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the 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.

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

From time to time, when we believe that market conditions are favorable, we use certain derivative financial instruments to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 2010 we employed natural gas and crude oil price swap agreements for portions of our 2010 production and natural gas price swap agreements and crude oil collar agreements for portions of our anticipated 2011 production to attempt to manage price risk more effectively. In addition, we have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting.

•

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 employing derivatives in the future. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A for further discussion concerning our use of derivatives.

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

Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or

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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.

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

Our operations are subject to extensive federal, state and local laws and regulations, including tax 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. 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. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and 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 state, regional and federal levels. On December 17, 2010, the EPA amended the “Mandatory Reporting of Greenhouse Gases” final rule (“Reporting Rule”) originally issued in September 2009. The Reporting Rule establishes a new comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent greenhouse gases to inventory and report their greenhouse gases emissions annually on a facility-by-facility basis. In addition, on December 15, 2009, the EPA published a Final Rule finding that current and projected concentrations of six key greenhouse gases in the atmosphere threaten public health and the welfare of current and future generations. The EPA also found that the combined emissions of these greenhouse gases from new motor vehicles and new motor vehicle engines contribute to pollution that threatens public health and welfare. This Final Rule, also known as the EPA’s Endangerment Finding, does not impose any requirements on industry or other entities directly. However, following issuance of the Endangerment Finding, EPA promulgated final motor vehicle GHG emission standards on April 1, 2010, the effect of which could reduce demand for motor fuels refined from crude oil. Also, according to the EPA, the final motor vehicle GHG standards will trigger construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, EPA issued a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi step process, with the largest sources first subject to permitting. Most recently, on November 8, 2010, EPA finalized new GHG reporting requirements for upstream petroleum and natural gas systems, which will be added to EPA’s GHG Reporting Rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year will now be required to report annual GHG emissions to EPA, with the first report due on March 31, 2012.

However, following issuance of the Endangerment Finding, the EPA promulgated final motor vehicle greenhouse gas emission standards on April 1, 2010, the effect of which could reduce demand for motor fuels refined from crude oil. Also, according to the EPA, the final motor vehicle greenhouse gas standards will trigger

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construction and operating permit requirements for stationary sources. Thus, on June 3, 2010, the EPA issued a final rule to address permitting of greenhouse gas emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule tailors the PSD and Title V programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. Most recently, on November 8, 2010, the EPA finalized new greenhouse gas reporting requirements for upstream petroleum and natural gas systems, which will be added to the Reporting Rule. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of C02 equivalent per year will now be required to report annual GHG emissions to the EPA, with the first report due on March 31, 2012.

Internationally, 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. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. While it is not possible at this time to predict how regulation 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. 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, 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.

The proposed U.S. federal budget for fiscal year 2012 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

On February 14, 2011, the Office Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2012, and the Treasury Department released a general explanation of tax related proposals in such budget. The proposed budget repeals many tax incentives and deductions that are currently used by U.S. oil and gas companies and imposes new taxes. The provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; increase in the taxation of foreign source income; repeal of the manufacturing tax deduction for oil and gas companies; and increase in the geological and geophysical amortization period for independent producers. Should some or all of these provisions 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 be voted on or 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 bylaws provide for a classified Board of Directors with staggered terms, and 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 limit 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

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may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.

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

The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors’ duty of care to equitable remedies such as injunction or rescission. Our charter limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:

•

for any breach of their duty of loyalty to the company or our stockholders;

•

for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

•

under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and

•

for any transaction from which the director derived an improper personal benefit.

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

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

See Item 1. “Business.”

ITEM 3.

LEGAL PROCEEDINGS

The Company is a defendant in various legal proceedings arising in the normal course of business. When deemed necessary, the Company establishes reserves for certain legal proceedings. All known liabilities are accrued based on an estimation process that includes the advice of legal counsel and subjective judgment of management. While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Environmental Matters

On November 4, 2009, the Company and the Pennsylvania Department of Environmental Protection (PaDEP) entered into a single settlement agreement (Consent Order) covering a number of separate, unrelated environmental issues occurring in 2008 and 2009, including releases of drilling mud and other substances, record keeping violations at various wells and alleged natural gas contamination of 13 water wells in Susquehanna County, Pennsylvania. The Company paid an aggregate $120,000 civil penalty with respect to all the matters covered by the Consent Order, which were consolidated at the request of the PaDEP.

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Company will provide a permanent source of potable water to 14 households, most of which the Company has already been supplying with water. The Company agreed to plug and abandon three vertical wells in close proximity to two of the households and to bring into compliance a fourth well in the nine square mile area of concern in Susquehanna County. The Company agreed to complete these actions prior to any new well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of concern. The Company also agreed to postpone drilling of new wells in the area of concern until all obligations under the consent orders are fulfilled. In addition, the Company agreed to take certain other actions if requested by PaDEP, which could include the plugging and abandonment of up to 10 additional wells. Under the First Modified Consent Order, the Company paid a $240,000 civil penalty and agreed to pay an additional $30,000 per month until all obligations under the First Modified Consent Order are satisfied.

On July 19, 2010, the Company and the PaDEP entered a Second Modification to Consent Order (Second Modified Consent Order) under which the Company and the PaDEP agreed that the Company has satisfactorily plugged and abandoned the three vertical wells and brought the fourth well into compliance. As a result, the Company and the PaDEP agreed that the PaDEP will commence the processing and issuance of new well drilling permits outside the area of concern so long as the Company continues to provide temporary potable water and offers to provide gas/water separators to the 14 households. No penalties were assessed under the Second Modified Consent Order.

As required by the Second Modified Consent Order, the Company made offers to provide whole-house water treatment systems to the 14 households. As required by the First Modified Consent Order, on August 5, 2010 the Company filed with the PaDEP its report, prepared by its experts, finding that the Company’s well drilling and development activities are not the source of methane gas reported to be in the groundwater and water wells in the area of concern.

Despite the Company’s vigorous efforts to comply with the various consent orders, in a September 14, 2010 letter to the Company, the PaDEP rejected the Company’s expert report and determined that the Company’s drilling activities continue to cause the unpermitted discharge of natural gas into the groundwater and continue to affect residential water supplies in the area of concern. The PaDEP directed the Company, in accordance with the First Modified Consent Order, to plug or take other remedial actions at the remaining 10 wells and to contact the PaDEP to discuss connecting the impacted water supplies into a community public water system to permanently eliminate the continuing adverse affect to those water supplies.

The Company believed that it was in full compliance with the various consent orders. In a September 28, 2010 reply letter to the PaDEP, the Company disagreed with the PaDEP’s rejection of the Company’s expert report, disagreed that the remaining 10 wells continue to impact groundwater and affect residential water supplies and disagreed that a community public water system is necessary or feasible. It was the Company’s position that offering installation of a whole-house water treatment system to the 14 households constituted compliance with the Company’s obligations under these consent orders.

On December 15, 2010, the Company entered a global settlement agreement and new consent order with the PaDEP (Global Settlement Agreement), which supersedes the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. Under the Global Settlement Agreement, among other things, the Company agreed to pay $4.2 million into separate escrow accounts for the benefit of each affected household, pay $500,000 to the PaDEP to reimburse the PaDEP for its costs, remediate two wells in the affected area, provide pressure, water quality and well headspace data to the PaDEP and offer water treatment to the affected households. The Global Settlement Agreement settles all outstanding issues and claims that are known and that could have been brought against the Company by the PaDEP relating to the wells in the affected area and the Consent Order, the First Modified Consent Order and the Second Modified Consent Order. It also allows the Company to begin hydraulic fracturing in the affected areas after providing the PaDEP with well pressure data and to commence drilling new wells in the affected area in the second quarter of 2011. Under the Global Settlement Agreement, the Company has no obligation to connect the impacted water supplies to a community public water system.

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On January 11, 2011, certain of the affected households appealed the Global Settlement Agreement to the Pennsylvania Environmental Hearing Board. A hearing on the merits of this appeal is not expected to occur until 2012.

As of December 31, 2010, the Company has paid $1.3 million in fines and penalties to the PaDEP, paid $0.6 million to two of the affected households and accrued a $3.6 million settlement liability related to this matter which is included in Other Liabilities in the Consolidated Balance Sheet.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information as of February 18, 2011 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.


Name	Age		Position	Officer Since
Dan O. Dinges		57	Chairman, President and Chief Executive Officer		2001
Scott C. Schroeder		48	Vice President and Chief Financial Officer and Treasurer		1997
G. Kevin Cunningham		57	Vice President, General Counsel		2010
Robert G. Drake		63	Vice President, Information Services and Operational Accounting		1998
Abraham D. Garza		64	Vice President, Human Resources		1998
Jeffrey W. Hutton		55	Vice President, Marketing		1995
Steven W. Lindeman		50	Vice President, Engineering and Technology		2011
Lisa A. Machesney		55	Vice President, Managing Counsel and Corporate Secretary		1995
James M. Reid		59	Vice President, Regional Manager South Region		2009
Todd M. Roemer		40	Controller		2010
Phillip L. Stalnaker		51	Vice President, Regional Manager North Region		2009

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 and Mr. Todd M. Roemer.

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

Mr. Lindeman was promoted to Vice President, Engineering and Technology, in February 2011. He began his career as a Drilling Engineer in Meadville, Pennsylvania with Cabot in 1982, has served in various management positions in many company offices over the years, including Pampa and Midland, Texas, Indiana, Meadville, and Pittsburgh, Pennsylvania, before moving to Houston in 1992, where he most recently served as Director of Engineering. Mr. Lindeman is a graduate of the University of Pittsburgh; he holds a Bachelor of Science degree in Chemical Engineering specializing in Petroleum Engineering. He has been a member of the Society of Petroleum Engineers since 1980.

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.

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PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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

High

Low

Dividends

2010

First Quarter

46.23

36.40

0.03

Second Quarter

40.51

30.33

0.03

Third Quarter

33.61

26.99

0.03

Fourth Quarter

37.85

28.27

0.03

2009

First Quarter

30.76

18.14

0.03

Second Quarter

36.90

24.38

0.03

Third Quarter

39.23

27.98

0.03

Fourth Quarter

45.73

34.14

0.03

As of February 1, 2011, there were 496 registered holders of the common stock.

ISSUER PURCHASES OF EQUITY SECURITIES

Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. There is no expiration date associated with the authorization. During 2010, 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, 2010 was 4,795,300.

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PERFORMANCE GRAPH

The following graph compares our common stock performance (“COG”) with the performance of the Standard & Poors’ 500 Stock Index and the Dow Jones US Exploration & Production Index for the period December 2005 through December 2010. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2005 and that all dividends were reinvested.

LOGO


CALCULATED VALUES	2005		2006		2007		2008		2009		2010
S&P 500		100.0		115.8		122.2		77.0		97.3		112.0
COG		100.0		134.9		180.1		116.4		195.8		170.6
Dow Jones US Exploration & Production		100.0		105.4		151.4		90.6		127.4		148.7

*	Year-end closing values.

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

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ITEM 6.

SELECTED FINANCIAL DATA

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


	Year Ended December 31,
(In thousands, except per share amounts)	2010		2009			2008		2007		2006
Statement of Operations Data
Operating Revenues	$	884,035	$	879,276		$	945,791	$	732,170	$	761,988
Impairment of Oil & Gas Properties and Other Assets ⁽¹⁾		40,903		17,622			35,700		4,614		3,886
Gain / (Loss) on Sale of Assets ⁽²⁾		106,294		(3,303	)		1,143		13,448		232,017
Gain on Settlement of Dispute ⁽³⁾		—		—			51,906		—		—
Income from Operations		266,439		282,269			372,012		274,693		528,946
Net Income		103,386		148,343			211,290		167,423		321,175
Basic Earnings per Share ⁽⁴⁾	$	0.99	$	1.43		$	2.10	$	1.73	$	3.32
Diluted Earnings per Share ⁽⁴⁾	$	0.98	$	1.42		$	2.08	$	1.71	$	3.26
Dividends per Common Share ⁽⁴⁾	$	0.12	$	0.12		$	0.12	$	0.11	$	0.08
Balance Sheet Data
Properties and Equipment, Net.	$	3,762,760	$	3,358,199		$	3,135,828	$	1,908,117	$	1,480,201
Total Assets		4,005,031		3,683,401			3,701,664		2,208,594		1,834,491
Current Portion of Long-Term Debt		—		—			35,857		20,000		20,000
Long-Term Debt		975,000		805,000			831,143		330,000		220,000
Stockholders’ Equity		1,872,700		1,812,514			1,790,562		1,070,257		945,198

⁽¹⁾	For discussion of impairment of oil and gas properties and other assets, refer to Note 2 of the Notes to the Consolidated Financial Statements.

⁽²⁾

Gain on Sale of Assets in 2010 includes $40.7 million from the sale of the Company’s investment in Tourmaline, $49.3 million from the sale of our Pennsylvania gathering infrastructure, $10.8 million from the sale of certain oil and gas properties in the Texas Panhandle, a $10.3 million gain on the sale of our Woodford shale properties, and an impairment loss of $5.8 million on certain oil and gas properties in Colorado. Gain on Sale of Assets for 2007 and 2006 reflects $12.3 million and $231.2 million, respectively, related to disposition of our offshore portfolio and certain south Louisiana properties, which was substantially completed in the third quarter of 2006.

⁽³⁾	Gain on Settlement of Dispute is associated with the Company’s settlement of a dispute in the fourth quarter of 2008. The dispute settlement includes the value of cash and properties received. See Note 8 of the Notes to the Consolidated Financial Statements.

⁽⁴⁾	All Earnings per Share and Dividends per Common Share figures have been retroactively adjusted for the 2-for-1 split of our common stock effective March 31, 2007.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

In 2009, we reorganized our operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with our Texas and Louisiana areas to form the South region. Additionally, we exited Canada through the sale of our properties in April 2009. Prior to the third quarter of 2009, we presented our geographic areas as East, Gulf Coast, West and Canada. Certain prior year amounts have been reclassified to reflect changes in presenting the geographic areas in which we conduct our operations.

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We operate in one segment, natural gas and oil development, exploitation and exploration, exclusively within the United States.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read “Forward-Looking Information” for further details.

OVERVIEW

Cabot Oil & Gas Corporation is a leading independent oil and gas company engaged in the development, exploitation, exploration, production and marketing of natural gas, crude oil and, to a lesser extent, natural gas liquids from its properties in the Continental United States. We also transport, store, gather and produce natural gas for resale. Our exploitation and exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. Our program is designed to be disciplined and balanced, with a focus on achieving strong financial returns.

We evaluate three types of investment alternatives that compete for available capital: drilling opportunities, financial opportunities such as debt repayment or repurchase of common stock and acquisition opportunities. Depending on circumstances, we allocate capital among the alternatives based on a rate-of-return approach. Our goal is to invest capital in the highest return opportunities available at any given time. At any one time, one or more of these may not be economically feasible.

Our financial results depend upon many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Price volatility in the commodity markets has remained prevalent in the last few years. Our realized natural gas and crude oil price was $5.54 per Mcf and $97.91 per Bbl, respectively, in 2010 and were significantly increased by our positions from our derivative instruments, which contributed approximately 22% of our realized revenues in 2010. In an effort to manage commodity price risk, we opportunistically enter into crude oil and natural gas price swaps and collars. These financial instruments are a component of our risk management strategy.

Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, NGL and crude oil prices and, therefore, we cannot determine with any degree of certainty what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success. See “Risk Factors—Natural gas and oil prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business” and “Risk Factors—Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable” in Item 1A.

The table below illustrates how natural gas prices have fluctuated by month over 2009 and 2010. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2009” and “2010” price is the natural gas price per Mcf realized by us and includes the realized impact of our natural gas derivative instruments, as applicable:


	Natural Gas Prices by Month - 2010
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	5.82	$	5.28	$	4.81	$	3.84	$	4.27	$	4.16	$	4.73	$	4.78	$	3.64	$	3.84	$	3.29	$	4.27
2010	$	6.95	$	6.47	$	6.28	$	5.35	$	5.49	$	5.60	$	5.66	$	5.64	$	4.84	$	4.99	$	4.66	$	5.39

	Natural Gas Prices by Month - 2009
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	6.16	$	4.49	$	4.07	$	3.65	$	3.33	$	3.54	$	3.96	$	3.37	$	2.84	$	3.72	$	4.28	$	4.49
2009	$	7.72	$	7.32	$	7.46	$	7.03	$	7.28	$	7.45	$	7.50	$	7.45	$	7.25	$	7.42	$	8.03	$	7.75

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The table below illustrates how crude oil prices have fluctuated by month over 2009 and 2010. “Index” represents the NYMEX monthly average crude oil price and our realized per barrel (Bbl) crude oil prices by month for 2009 and 2010. The “2009” and “2010” price is the crude oil price per Bbl realized by us and includes the realized impact of our crude oil derivative instruments:


	Crude Oil Prices by Month - 2010
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	72.47	$	77.62	$	80.16	$	81.25	$	83.45	$	68.01	$	77.21	$	77.44	$	73.46	$	73.52	$	81.77	$	81.51
2010	$	101.75	$	96.32	$	95.25	$	97.07	$	94.48	$	98.82	$	99.00	$	101.47	$	94.95	$	101.01	$	97.51	$	100.24

	Crude Oil Prices by Month - 2009
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	41.92	$	39.26	$	48.06	$	49.95	$	59.21	$	69.70	$	64.29	$	71.14	$	69.47	$	75.82	$	78.15	$	74.60
2009	$	75.41	$	73.98	$	76.29	$	78.86	$	85.94	$	86.26	$	82.22	$	92.16	$	87.54	$	92.13	$	95.35	$	95.41

Natural gas revenues decreased from 2009 to 2010 as a result of decreased commodity market prices partially offset by increased natural gas production. Crude oil revenues increased slightly from 2009 to 2010 primarily due to increased realized prices, partially offset by decreased crude oil production. Prices, including the realized impact of derivative instruments, decreased by 26% for natural gas and increased by 14% for oil.

We drilled 113 gross wells with a success rate of 98% in 2010 compared to 143 gross wells with a success rate of 95% in 2009. Total capital and exploration expenditures increased by $251.1 million to $891.5 million in 2010 compared to $640.4 million in 2009. This increase was due to a $230.6 million increase in the North region substantially driven by an expanded Marcellus horizontal drilling program in northeast Pennsylvania to hold acreage and $42.8 million in the South region due to due to an increase in lease acquisitions to establish a greater position in the oil window of the Eagle Ford shale. We believe our cash on hand and operating cash flow in 2011 will be sufficient to fund our budgeted capital and exploration spending of approximately $600 million. Any additional needs are expected to be funded by borrowings from our credit facility.

Our 2011 strategy will remain consistent with 2010. We will remain focused on our strategies of pursuing lower risk drilling opportunities that provide more predictable results on our accumulated acreage position. Additionally, we intend to maintain spending discipline and manage our balance sheet in an effort to ensure sufficient liquidity, including cash resources and available credit. In the current year we have allocated our planned program for capital and exploration expenditures primarily to the Marcellus shale in northeast Pennsylvania, and the Eagle Ford shale in south Texas. We believe these strategies are appropriate for our portfolio of projects and the current industry environment and will continue to add shareholder value over the long-term.

The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read “Forward-Looking Information” for further details.

FINANCIAL CONDITION

Capital Resources and Liquidity

Our primary sources of cash in 2010 were from funds generated from the sale of natural gas and crude oil production (including hedge realizations), borrowings under our revolving credit facility, issuance of private placement debt and the sales of properties and other assets during the year. These cash flows were primarily used to fund our development and exploratory expenditures, in addition to repayments for debt and related interest, payments for debt issuance costs, contributions to our pension plan and dividends. See below for additional discussion and analysis of cash flow.

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

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


	Year Ended December 31,
(In thousands)	2010			2009			2008
Cash Flows Provided by Operating Activities	$	484,911		$	614,052		$	634,447
Cash Flows Used in Investing Activities		(613,741	)		(531,027	)		(1,452,289	)
Cash Flows Provided by / (Used in) Financing Activities		144,621			(70,968	)		827,445

Net Increase / (Decrease) in Cash and Cash Equivalents	$	15,791		$	12,057		$	9,603

Operating Activities. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities in 2010 decreased by $129.1 million over 2009. This decrease was mainly due to a decrease in oil and gas revenues and higher operating and interest expense. Average realized natural gas prices decreased by 26% in 2010 compared to 2009 and average realized crude oil prices increased by 14% over the same period. Equivalent production volumes increased by 27% in 2010 compared to 2009 primarily due to higher natural gas production. 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 continue to decline during 2011.

For 2010, we had natural gas price swaps covering 35.9 Bcf, or 29%, of our 2010 natural gas production at an average price of $9.30 per Mcf. We also had crude oil price swaps covering 730 Mmbl, or 90%, of our 2010 crude oil production at an average price of $104.25 per Bbl. As of December 31, 2010, we have natural gas price swaps covering 12.9 Bcf of our 2011 gas production at an average price of $6.24 per Mcf and crude oil collars covering 365 MBbls of our 2011 crude oil production, with a floor of $80.00 per Bbl and a ceiling of $93.25 per Bbl. Accordingly, based on our current hedge position, we will be more subject to the effects of natural gas and crude oil price volatility in 2011 than in 2010. In addition, given the current market for derivatives, if we were to hedge all our 2011 production, we would expect our realized prices to be lower than our 2010 realized prices.

Net cash provided by operating activities in 2009 decreased by $20.4 million over 2008. This decrease was mainly due to a decrease in oil and gas revenues, partially offset by lower operating, interest and tax expense. Average realized natural gas prices decreased by 11% in 2009 compared to 2008 and average realized crude oil prices decreased by 4% over the same period. Equivalent production volumes increased by 8% in 2009 compared to 2008 as a result of higher natural gas and crude oil production.

See “Results of Operations” for a discussion on commodity prices and a review of the impact of prices and volumes on sales revenue.

Investing Activities. The primary uses of cash in investing activities were capital spending and exploration expenses. We established the 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

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expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased by $82.7 million from 2009 to 2010 and decreased by $921.3 million from 2008 to 2009. The increase from 2009 to 2010 was due to an increase of $246.4 million in acquisitions and capital and exploration expenditures partially offset by an increase of $163.3 million of proceeds from the sale of assets.

The decrease from 2008 to 2009 was due to a decrease of $843.2 million in acquisitions and capital expenditures and an increase of $78.1 million of proceeds from the sale of assets. In August 2008, we completed the acquisition of producing properties, leasehold acreage and a natural gas gathering infrastructure in east Texas for total net cash consideration of approximately $604.0 million.

Financing Activities. Cash flows provided by financing activities increased by $215.6 million from 2009 to 2010. This was primarily due to an increase in borrowings of $420.0 million, partially offset by an increase in repayments of debt of $188.0 million, an increase in cash paid for capitalized debt issuance costs by a total of $3.4 million and a decrease of $13.7 million in the tax benefit associated with stock-based compensation.

Cash flows provided by financing activities decreased by $898.4 million from 2008 to 2009. This was primarily due to a decrease in borrowings from debt of $787 million, partially offset by a decrease in repayments of debt of $208 million, and a decrease in net proceeds from the sale of common stock of $316.1 million primarily due to our June 2008 issuance of common stock in a public offering. Common stock proceeds and debt borrowings in 2008 were largely used to finance the acquisition of east Texas properties and undeveloped acreage. Cash paid for capitalized debt issuance costs and dividends increased by a total of $6.4 million, partially offset by an increase of $3.1 million in the tax benefit associated with stock-based compensation.

At December 31, 2010, we had $213.0 million of borrowings outstanding under our unsecured credit facility at a weighted-average interest rate of 3.1%.

In December 2010, we completed a private placement of $175.0 million aggregate principal amount of senior unsecured fixed-rate notes with a weighted-average interest rate of 5.58%, consisting of amounts due in January 2021, 2023 and 2026.

In September 2010, we amended and restated our revolving credit facility to increase the available credit line to $900 million with an accordion feature allowing us to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount, and to extend the term to September 2015. The available credit line is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks based on our reserve reports and engineering reports) and certain other assets and the outstanding principal balance of our senior notes. The amended facility provides for a $1.5 billion borrowing base. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. As of December 31, 2010, our available credit under our credit facility is $525.0 million.

In June 2010, we amended the agreements governing our credit facility and senior notes to amend the required asset coverage ratio (the present value of our proved reserves plus working capital to debt) contained in the agreements. The amendment also changed the ratio for maximum calculated indebtedness to borrowing base (as defined in the credit facility agreement).

In July 2008, we completed a private placement of $425 million aggregate principal amount of senior unsecured fixed-rate notes with a weighted-average interest rate of 6.51%, consisting of amounts due in July 2018, 2020 and 2023. In December 2008, we completed a private placement of $67 million aggregate principal amount of senior unsecured 9.78% fixed-rate notes due in December 2018.

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In June 2008, we entered into an underwriting agreement pursuant to which we sold an aggregate of 5,002,500 shares of common stock at a price to us of $62.66 per share. We received $313.5 million in net proceeds, after deducting underwriting discounts and commissions. These net proceeds were used temporarily to reduce outstanding borrowings under our revolving credit facility prior to funding a portion of the purchase price of our east Texas acquisition, which closed in the third quarter of 2008. Immediately prior to (and in connection with) this issuance, we retired 5,002,500 shares of treasury stock, which had a weighted-average purchase price of $16.46.

Management believes that, with internally generated cash, existing cash and availability under our revolving credit facility, we have the capacity to finance our spending plans and maintain our strong financial position. At the same time, we will closely monitor the capital markets.

Capitalization

Information about our capitalization is as follows:


	December 31,
(Dollars in thousands)	2010			2009
Debt ⁽¹⁾	$	975,000		$	805,000
Stockholders’ Equity	$	1,872,700		$	1,812,514

Total Capitalization	$	2,847,700		$	2,617,514

Debt to Capitalization		34	%		31	%
Cash and Cash Equivalents	$	55,949		$	40,158

⁽¹⁾	Includes $213.0 million and $143.0 million of borrowings outstanding under our revolving credit facility at December 31, 2010 and 2009, respectively.

For the year ended December 31, 2010, we paid dividends of $12.5 million ($0.12 per share) on our common stock. A regular dividend has been declared for each quarter since we became a public company in 1990.

Capital and Exploration Expenditures

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

The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 2010.


(In thousands)	2010		2009		2008
Capital Expenditures
Drilling and Facilities ⁽¹⁾	$	654,153	$	401,143	$	624,344
Leasehold Acquisitions		130,675		145,681		152,666
Acquisitions		801		394		624,975
Pipeline and Gathering		54,811		32,861		36,900
Other		8,368		9,506		10,855

		848,808		589,585		1,449,740
Exploration Expense		42,725		50,784		31,200

Total	$	891,533	$	640,369	$	1,480,940

⁽¹⁾	Includes Canadian currency translation effects of $4.6 million and $(27.7) million in 2009 and 2008, respectively. There was no impact from Canadian currency translation in 2010.

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We plan to drill approximately 110 gross wells (83.1 net) in 2011 compared with 113 gross wells (87.1 net) drilled in 2010. This 2011 drilling program includes approximately $600 million in total capital and exploration expenditures, down from $891.5 million in 2010. This decline is primarily due to the lower well count together with lower projected lease acquisition expenditures as the result of our reduced program spending due to lower commodity prices and reduced infrastructure investments. We will continue to assess the natural gas and crude oil price environment and our liquidity position and may increase or decrease the capital and exploration expenditures accordingly.

There are many factors that impact our depreciation, depletion and amortization (DD&A) rate. These include reserve additions and revisions, development costs, impairments and changes in anticipated production in future periods. In 2011, management expects a small decrease in our DD&A rate primarily due to increased production and reserve additions in the Marcellus shale. Such changes in our DD&A rate and related expense do not have an impact on our cash flows.

Contractual Obligations

Our material contractual obligations include long-term debt, interest on long-term debt, firm gas transportation agreements, drilling rig commitments and operating leases. We have no off-balance sheet debt or other similar unrecorded obligations.

A summary of our contractual obligations as of December 31, 2010 are set forth in the following table:


			Payments Due by Year
(In thousands)	Total		2011		2012 to 2013		2014 to 2015		2016 & Beyond
Long-Term Debt ⁽¹⁾	$	975,000	$	—	$	75,000	$	—	$	900,000
Interest on Long-Term Debt ⁽²⁾		448,894		59,140		112,780		99,098		177,876
Firm Gas Transportation Agreements ⁽³⁾		485,619		32,504		64,040		56,712		332,363
Operating Leases ⁽³⁾		22,158		5,414		9,902		6,842		—

Total Contractual Cash Obligations	$	1,931,671	$	97,058	$	261,722	$	162,652	$	1,410,239

⁽¹⁾	At December 31, 2010, we had $213.0 million of debt outstanding under our revolving credit facility. See Note 5 of the Notes to the Consolidated Financial Statements for details of long-term debt.

⁽²⁾

Interest payments have been calculated utilizing the fixed rates of our $762.0 million long-term debt outstanding at December 31, 2010. Interest payments on our revolving credit facility were calculated by assuming that the December 31, 2010 outstanding balance of $213.0 million will be outstanding through the September 2015 maturity date. A constant interest rate of 3.8% was assumed, which was the 2010 weighted-average interest rate. Actual results will differ from these estimates and assumptions.

⁽³⁾	For further information on our obligations under firm gas transportation agreements and operating leases, see Note 8 of the Notes to the Consolidated Financial Statements.

Amounts related to our asset retirement obligations are not included in the above table given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at December 31, 2010 was $72.3 million, up from $29.7 million at December 31, 2009, primarily due to $40.4 million in revisions of previous estimates due to increased plugging and abandonment costs and $1.9 million in accretion expense during 2010. See Note 9 of the Notes to the Consolidated Financial Statements for further details.

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.

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Successful Efforts Method of Accounting

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

Oil and Gas Reserves

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

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

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 method calculation. If the estimates of proved reserves were to be reduced, the rate at which we record DD&A expense would increase, reducing net income. Such a reduction in reserves may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. A five percent positive or negative revision to proved reserves throughout the Company would decrease or increase the DD&A rate by approximately ($0.10) to $0.12 per Mcfe. 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 have a ($0.06) to $0.07 per Mcfe impact 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 Accounting Standards Codification (ASC) 360, “Property, Plant, and Equipment.” 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 the impairment of our oil and gas properties 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 crude oil and natural gas prices, operating costs and anticipated production from proved reserves 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. In the event that commodity prices remain low or continue to 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 oil.

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Costs attributable to our unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past experience and average property 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 regions has not significantly changed. 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 $17.3 million or decrease by approximately $12.3 million, respectively per year.

In the past, based on the customary terms of the leases, the average leasehold life in the South region has been shorter than the average life in the North region. Average property lives in the North and South regions have been five and three years, respectively. 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 relates to the plugging and abandonment of oil and gas wells and to a lesser extent meter stations, pipelines, processing plants and compressors. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. The recognition of an asset retirement obligation requires management to make assumptions that include estimated plugging and abandonment costs, timing of settlements, inflation rates and discount rate. In periods subsequent to initial measurement, the asset retirement cost is allocated to expense using a systematic and rational method over the assets useful life, while increases in the discounted ARO liability resulting from the passage of time (accretion expense) is reflected as depreciation, depletion and amortization expense.

Accounting for Derivative Instruments and Hedging Activities

We follow the accounting prescribed in ASC 815. Under ASC 815, 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, is recorded currently in earnings as a component of Natural Gas and Crude Oil and Condensate Revenue in the Consolidated Statement of Operations.

The fair value of our derivative instruments are measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. 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. In times where we have net derivative contract liabilities, our nonperformance risk is evaluated using a market credit spread provided by our bank.

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Employee Benefit Plans

Our costs of long-term employee benefits, particularly pension and 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 projected pension obligation and related costs include discount rates, expected return on plan assets, and rate of compensation increases, while the 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 a fair value based method of accounting prescribed under ASC 718. 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 the fair value, either a binomial or Black-Scholes valuation model may be used. 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.

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” and “Environmental Regulations” in the “Other Business Matters” section of Item 1 for a discussion of these regulations.

Restrictive Covenants. Our ability to incur debt and to make certain types of investments is subject to certain restrictive covenants in our various debt instruments. Among other requirements, our revolving credit agreement and our senior notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. In addition, we are required to maintain an asset coverage ratio of the present value of proved reserves plus working capital to debt of 1.75 to 1.0 and a current ratio of 1.0 to 1.0. Our senior notes require us to maintain a ratio of cash and proved reserves to indebtedness and other liabilities of 1.75 to 1.0. At December 31, 2010, we were in compliance in all material respects with all restrictive covenants on both the revolving credit agreement and notes. In the unforeseen event that we fail to comply with these covenants, we may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation.

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

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ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas 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 under ASC 360, “Property, Plant, and Equipment.” Because our reserves are predominantly natural gas, changes in natural gas prices may have a more significant impact on our financial results.

The majority of our production is sold at market responsive prices. Generally, if the related commodity index falls, 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 price collars and swap arrangements to reduce the impact of declining prices on our revenue. Under both arrangements, there is also a risk that the movement of index prices may result in our inability to realize the full benefit of an improvement in market conditions.

Settlement of Dispute. In December 2008, we settled a dispute with a third party and as a result recorded a gain of $51.9 million. The dispute involved the propriety of possession of our intellectual property by a third party. The settlement was comprised of $20.2 million in cash paid by the third party to us and $31.7 million related to the fair value of unproved property rights transferred by the third party to us. The fair market value of the unproved property rights was determined based on observable market costs and conditions over a recent time period. Values were pro-rated by property based on the primary term remaining on the properties.

Recently Adopted Accounting Standards

In February 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-09, “Subsequent Events,” which amends ASC 855 to eliminate the requirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and its adoption had no impact on the Company’s financial position, results of operations or cash flows.

Effective January 1, 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC 820-10-50 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). Accordingly, the Company will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on the Company’s financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please refer to Note 14.

Forward-Looking Information

The statements regarding future financial and operating performance and results, 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 regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. See “Risk Factors” in Item 1A for additional information about these risks and

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uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

RESULTS OF OPERATIONS

2010 and 2009 Compared

We reported net income for 2010 of $103.4 million, or $0.99 per share. During 2009, we reported net income of $148.3 million, or $1.43 per share. Net income decreased in 2010 by $45.0 million, primarily due to increased operating, income tax and interest expenses and decreased operating revenues partially offset by increased gain on sale of assets. Operating revenues decreased by $35.2 million largely due to decreases in natural gas and brokered natural gas revenues, partially offset by an increase in crude oil and condensate revenues. Operating expenses increased by $90.2 million between periods due primarily to increases in depreciation, depletion and amortization, impairment of oil and gas properties and other assets, general and administrative expense and direct operations. These increases were partially offset by decreases in brokered natural gas cost, taxes other than income and exploration expense.

Revenue, Price and Volume Variances

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


	Year Ended December 31,				Variance
	2010		2009		Amount		Percent
Revenue Variances (In thousands)
Natural Gas ⁽¹⁾	$	694,803	$	731,688	$	(36,885)		(5	%)
Brokered Natural Gas		65,281		75,283		(10,002)		(13	%)
Crude Oil and Condensate		79,091		69,936		9,155		13	%
Other		5,086		4,323		763		18	%

⁽¹⁾	Natural Gas Revenues exclude the unrealized loss from the change in fair value of our basis swaps of $0.2 million and $2.0 million in 2010 and 2009, respectively.


	Year Ended December 31,				Variance						Increase (Decrease) (In thousands)
	2010		2009		Amount			Percent			Increase (Decrease) (In thousands)
Price Variances
Natural Gas ⁽¹⁾	$	5.54	$	7.47	$	(1.93	)		(26	%)	$	(242,758	)
Crude Oil and Condensate ⁽²⁾	$	97.91	$	85.52	$	12.39			14	%		10,010

Total											$	(232,748	)

Volume Variances
Natural Gas (Mmcf)		125,474		97,914		27,560			28	%	$	205,873
Crude Oil and Condensate (Mbbl)		808		818		(10	)		(1	%)		(855	)

Total											$	205,018

⁽¹⁾	These prices include the realized impact of derivative instrument settlements, which increased the price by $1.23 per Mcf in 2010 and by $3.80 per Mcf in 2009.

⁽²⁾	These prices include the realized impact of derivative instrument settlements, which increased the price by $22.31 per Bbl in 2010 and by $28.85 per Bbl in 2009.

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Natural Gas Revenues

The decrease in Natural Gas Revenue of $36.9 million, excluding the impact of the unrealized gains and losses discussed above, is due primarily to the decrease in realized natural gas prices, decreased production in the South region associated with normal production declines, delays in completions and a shift from gas to oil projects, as well as the sale of our Canadian properties in April 2009. Partially offsetting these decreases was an increase in natural gas production in the North region associated with increased drilling and the start up of a portion of the Lathrop compressor station in the Marcellus shale at the end of the second quarter of 2010.

Crude Oil and Condensate Revenues

The $9.2 million increase in crude oil and condensate revenues is primarily due to an increase in realized crude oil prices and an increase in crude oil production in the South region associated with the Eagle Ford shale and Pettet formation production. These increases are partially offset by lower production in the North region as well as the sale of our Canadian properties in April 2009.

Brokered Natural Gas Revenue and Cost


	Year Ended December 31,				Variance						Price and Volume Variances (In thousands)
	2010		2009		Amount			Percent			Price and Volume Variances (In thousands)
Brokered Natural Gas Sales
Sales Price ($/Mcf)	$	5.41	$	5.95	$	(0.54	)		(9	%)	$	(6,527	)
Volume Brokered (Mmcf)	x	12,072	x	12,656		(584	)		(5	%)		(3,475	)

Brokered Natural Gas Revenues (In thousands)	$	65,281	$	75,283							$	(10,002	)

Brokered Natural Gas Purchases
Purchase Price ($/Mcf)	$	4.68	$	5.30	$	(0.62	)		(12	%)	$	7,489
Volume Brokered (Mmcf)	x	12,072	x	12,656		(584	)		(5	%)		3,075

Brokered Natural Gas Cost (In thousands)	$	56,466	$	67,030							$	10,564

Brokered Natural Gas Margin (In thousands)	$	8,815	$	8,253							$	562

The increased brokered natural gas margin of $0.6 million is a result of a lesser decrease in sales price than in purchase price, partially offset by a decrease in volumes brokered.

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Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:


	Year Ended December 31,
	2010					2009
(In thousands)	Realized		Unrealized			Realized		Unrealized
Operating Revenues—Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas	$	154,960	$	—		$	371,915	$	—
Crude Oil		18,030		—			23,112		—

Total Cash Flow Hedges		172,990		—			395,027		—

Other Derivative Financial Instruments
Natural Gas Basis Swaps		—		(226	)		—		(1,954	)

Total Other Derivative Financial Instruments		—		(226	)		—		(1,954	)

Total Cash Flow Hedges and Other Derivative Financial Instruments	$	172,990	$	(226	)	$	395,027	$	(1,954	)

Operating and Other Expenses


	Year Ended December 31,					Variance
(In thousands)	2010			2009		Amount			Percent
Operating and Other Expenses
Brokered Natural Gas Cost	$	56,466		$	67,030	$	(10,564	)		(16	%)
Direct Operations—Field and Pipeline		99,642			93,985		5,657			6	%
Taxes Other Than Income		37,894			44,649		(6,755	)		(15	%)
Exploration		42,725			50,784		(8,059	)		(16	%)
Depreciation, Depletion and Amortization		327,083			251,260		75,823			30	%
Impairment of Oil and Gas Properties and Other Assets		40,903			17,622		23,281			132	%
General and Administrative		79,177			68,374		10,803			16	%

Total Operating Expense	$	683,890		$	593,704	$	90,186			15	%
(Gain) / Loss on Sale of Assets	$	(106,294	)	$	3,303	$	(109,597	)		(3,318	%)
Interest Expense and Other		67,941			58,979		8,962			15	%
Income Tax Expense		95,112			74,947		20,165			27	%

Total costs and expenses from operations increased by $90.2 million from 2009 to 2010. The primary reasons for this fluctuation are as follows:

•

Depreciation, Depletion and Amortization increased by $75.8 million from 2009 to 2010, primarily due to increased depreciation and depletion from increased capital spending and higher equivalent production volumes. Amortization of unproved properties increased $17.6 million primarily due to increased unproved leasehold costs in the Marcellus shale and the Eagle Ford shale in south Texas in late 2009 and continuing into 2010.

•

Impairment of Oil & Gas Properties and Other Assets increased by $23.3 million from 2009 to 2010. Impairments in 2010 consisted of a $35.8 million impairment of two south Texas fields due to continued price declines and limited activity and a $5.1 million impairment related to drilling and service equipment.

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•

General and Administrative expenses increased by $10.8 million from 2009 to 2010. The increase is primarily due to a $9.9 million increase in legal expenses primarily related to the December 2010 PaDEP settlement, ongoing litigation and related legal fees, a $8.3 million increase in pension expense primarily due to termination and amendment of our pension plans and a $2.4 million increase in incentive compensation. These increases were partially offset by an $8.5 million decrease in stock compensation expense primarily due to prior year awards that fully vested in February 2010 and a reduction in stock price.

•

Brokered Natural Gas Cost decreased by $10.6 million from 2009 to 2010. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

•

Exploration expense decreased by $8.1 million from 2009 to 2010 primarily due to lower dry hole costs as a result of drilling one dry hole in 2010 compared to two dry holes in 2009. The decrease was partially offset by higher geophysical and geological expenses associated with seismic purchases related to our Marcellus, Eagle Ford and Haynesville shale properties during 2010.

•

Taxes Other Than Income decreased by $6.8 million from 2009 to 2010 primarily due to decreased production and ad valorem taxes due to lower natural gas prices and property values partially offset by increased business and occupational taxes and franchise taxes.

•

Direct Operations expenses increased by $5.7 million from 2009 to 2010 primarily due to lease maintenance expense in both the North and South regions and plug and abandonment costs in the North region related to plugging and abandoning three vertical wells in accordance with the PaDEP’s Second Modified Consent Order.

Gain / (Loss) on Sale of Assets

Gain / (Loss) on Sale of Assets increased by $109.6 million from 2009 to 2010. During 2010, we recognized a gain of $49.3 million from the sale of our Pennsylvania gathering infrastructure, $40.7 million from the sale of our investment in Tourmaline, $10.8 million from the sale of certain oil and gas properties in the Texas Panhandle, $10.3 million on the sale of our Woodford shale properties, partially offset by an impairment loss of $5.1 million on certain oil and gas properties in Colorado.

During 2009, we recognized a $16.0 million loss on sale of assets primarily due to the sale of the Canadian properties, partially offset by a $12.7 million gain on sale of assets related to the sale of our Thornwood properties in the North region.

Interest Expense, Net

Interest expense, net increased by $9.0 million from 2009 to 2010 primarily due to an increase in weighted-average borrowings under our credit facility based on daily balances of approximately $340.4 million during 2010 compared to approximately $166 million during 2009, and to a lesser extent to the $175.0 million of debt we issued in December 2010. The weighted-average effective interest rate on the credit facility decreased to approximately 3.8% during 2010 compared to approximately 4.0% during 2009. Interest expense in 2010 also includes a make-whole premium payment of $2.8 million associated with the early payment of $75.0 million of the 7.33% fixed rate notes that were due in July 2011.

Income Tax Expense

Income tax expense increased by $20.2 million due to a higher effective tax rate offset by a decrease in our pre-tax income. The effective tax rates for 2010 and 2009 were 47.9% and 33.6%, respectively. The effective tax rate was higher primarily due to an increase in our state rates used in establishing deferred income taxes mainly due to a shift in our state apportionment factors to higher rate states, primarily in Pennsylvania, as a result of our increased focus on development of our Marcellus shale properties.

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2009 and 2008 Compared

We reported net income for 2009 of $148.3 million, or $1.43 per share. During 2008, we reported net income of $211.3 million, or $2.10 per share. Net income decreased in 2009 by $63.0 million, primarily due to decreased operating revenues and increased operating expenses, partially offset by increased gain on sale of assets. Operating revenues decreased by $66.5 million largely due to decreases in brokered natural gas and natural gas revenues. Operating expenses decreased by $33.1 million between periods due primarily to decreases in brokered natural gas costs, taxes other than income and general and administrative expenses, partially offset by increased depreciation, depletion and amortization, exploration expense and direct operations. In addition, net income was impacted in 2009 by higher interest expense, decreased income tax expense and, to a lesser extent, loss on sale of assets. Income tax expense was lower in 2009 as a result of a decrease in operating income, as discussed above, and a decrease in the effective tax rate. The decrease in the effective tax rate is primarily due to an overall reduction in state deferred tax liabilities and tax benefits associated with foreign tax credits.

Revenue, Price and Volume Variances

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


	Year Ended December 31,				Variance
	2009		2008		Amount			Percent
Revenue Variances (In thousands)
Natural Gas ⁽¹⁾	$	731,688	$	758,755	$	(27,067	)		(4	%)
Brokered Natural Gas		75,283		114,220		(38,937	)		(34	%)
Crude Oil and Condensate		69,936		69,711		225			0	%
Other		4,323		3,105		1,218			39	%

⁽¹⁾	Natural Gas Revenues exclude the unrealized loss from the change in fair value of our basis swaps of $2.0 million in 2009. There was no impact from the unrealized change in natural gas derivative fair value for 2008.


	Year Ended December 31,				Variance						Increase (Decrease) (In thousands)
	2009		2008		Amount			Percent			Increase (Decrease) (In thousands)
Price Variances
Natural Gas ⁽¹⁾	$	7.47	$	8.39	$	(0.92	)		(11	%)	$	(89,606	)
Crude Oil and Condensate ⁽²⁾	$	85.52	$	89.11	$	(3.59	)		(4	%)		(2,966	)

Total											$	(92,572	)

Volume Variances
Natural Gas (Mmcf)		97,914		90,425		7,489			8	%	$	62,539
Crude Oil and Condensate (Mbbl)		818		782		36			5	%		3,191

Total											$	65,730

⁽¹⁾	These prices include the realized impact of derivative instrument settlements, which increased the price by $3.80 per Mcf in 2009 and by $0.20 per Mcf in 2008.

⁽²⁾	These prices include the realized impact of derivative instrument settlements, which increased the price by $28.25 per Bbl in 2009 and decreased the price by $6.33 per Bbl in 2008.

Natural Gas Revenues

The decrease in Natural Gas Revenue of $27.1 million, excluding the impact of the unrealized gains and losses discussed above, is almost entirely due to the sale of our Canadian properties and a decrease in realized natural gas prices that was essentially offset by an increase in natural gas production. This increase in natural gas

- 48 -

production was primarily a result of increased production in the North region associated with the initiation of production in Susquehanna County, Pennsylvania in the third quarter of 2008 and increased drilling in the Marcellus shale prospect in Susquehanna County as well as increased natural gas production in the South region associated with the properties we acquired in east Texas in August 2008 and drilling in the Angie field. Partially offsetting these production gains were decreases in production in Canada due to the sale of substantially all of our Canadian properties in April 2009.

Crude Oil and Condensate Revenues

The increase in crude oil production, partially offset by a decrease in realized crude oil prices, resulted in a net revenue increase of $0.2 million. The increase in crude oil production was primarily the result of increased production in the South region associated with the properties we acquired in the east Texas acquisition in August 2008 and an increase related to Pettet formation production in the Angie field, partially offset by a decrease in production in Canada due to the sale of substantially all of our Canadian properties in April 2009.

Brokered Natural Gas Revenue and Cost


	Year Ended December 31,				Variance						Price and Volume Variances (In thousands)
	2009		2008		Amount			Percent			Price and Volume Variances (In thousands)
Brokered Natural Gas Sales
Sales Price ($/Mcf)	$	5.95	$	10.39	$	(4.44	)		(43	%)	$	(56,185	)
Volume Brokered (Mmcf)	x	12,656	x	10,996		1,660			15	%		17,248

Brokered Natural Gas Revenues (In thousands)	$	75,283	$	114,220							$	(38,937	)

Brokered Natural Gas Purchases
Purchase Price ($/Mcf)	$	5.30	$	9.14	$	(3.84	)		(42	%)	$	48,592
Volume Brokered (Mmcf)	x	12,656	x	10,996		1,660			15	%		(15,173	)

Brokered Natural Gas Cost (In thousands)	$	67,030	$	100,449							$	33,419

Brokered Natural Gas Margin (In thousands)	$	8,253	$	13,771							$	(5,518	)

The decreased brokered natural gas margin of $5.5 million is a result of a decrease in sales price that outpaced the decrease in purchase price, partially offset by an increase in volumes brokered.

Impact of Derivative Instruments on Operating Revenues

The following table reflects the realized impact of cash settlements and the net unrealized change in fair value of derivative instruments:


	Year Ended December 31,
	2009					2008
(In thousands)	Realized		Unrealized			Realized			Unrealized
Operating Revenues—Increase / (Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	371,915	$	—		$	17,972		$	—
Crude Oil		23,112		—			(4,951	)		—

Total Cash Flow Hedges		395,027		—			13,021			—

Other Derivative Financial Instruments
Natural Gas Basis Swaps		—		(1,954	)		—			—

Total Other Derivative Financial Instruments		—		(1,954	)		—			—

Total Cash Flow Hedges and Other Derivative Financial Instruments	$	395,027	$	(1,954	)	$	13,021		$	—

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Operating and Other Expenses


	Year Ended December 31,					Variance
(In thousands)	2009		2008			Amount			Percent
Operating and Other Expenses
Brokered Natural Gas Cost	$	67,030	$	100,449		$	(33,419	)		(33	%)
Direct Operations—Field and Pipeline		93,985		91,839			2,146			2	%
Taxes Other Than Income		44,649		66,540			(21,891	)		(33	%)
Exploration		50,784		31,200			19,584			63	%
Depreciation, Depletion and Amortization		251,260		226,915			24,345			11	%
Impairment of Oil and Gas Properties and Other Assets		17,622		35,700			(18,078	)		(51	%)
General and Administrative		68,374		74,185			(5,811	)		(8	%)

Total Operating Expense	$	593,704	$	626,828		$	(33,124	)		(5	%)
(Gain) / Loss on Sale of Assets	$	3,303	$	(1,143	)	$	4,446			389	%
Interest Expense and Other		58,979		36,389			22,590			62	%
Income Tax Expense		74,947		124,333			(49,386	)		(40	%)

Total costs and expenses from operations decreased by $33.1 million in 2009 from 2008. The primary reasons for this fluctuation are as follows:

•

Brokered Natural Gas Cost decreased by $33.4 million from 2008 to 2009. See the preceding table titled “Brokered Natural Gas Revenue and Cost” for further analysis.

•

Depreciation, Depletion and Amortization increased by $24.3 million from 2008 to 2009. This is primarily due to the impact on the DD&A rate of higher capital costs and higher natural gas and oil production volumes, including the east Texas acquisition in August 2008. Amortization of unproved properties decreased by $11.5 million from 2008 to 2009, primarily due to the $17.0 million impairment of Mississippi, Montana and North Dakota leases in 2008 offset by increased lease acquisition costs incurred in several exploratory and developmental areas in the North and in east Texas as well as the amortization of undeveloped costs associated with the east Texas acquisition in August 2008.

•

Taxes Other Than Income decreased by $21.9 million from 2008 to 2009 due to lower production taxes as a result of lower average natural gas and crude oil prices.

•

Exploration expense increased by $19.6 million from 2008 to 2009 primarily due to higher charges for idle contract rigs and higher dry hole and geological and geophysical costs.

•

Impairment of Oil & Gas Properties and Other Assets decreased by $18.1 million from 2008 to 2009. Impairments in 2009 consisted of approximately $12.0 million in the Fossil Federal field in San Miguel County, Colorado resulting from lower well performance and $5.6 million in the Beaurline field in Hidalgo County, Texas resulting from lower well performance.

•

General and Administrative expenses decreased by $5.8 million from 2008 to 2009. This is primarily due to decreased stock compensation expense largely related to a reduction in supplemental employee compensation expense of $14.7 million, partially offset by an increase in performance share award expense of $5.5 million and an increase in pension expense related to our qualified pension plan.

•

Direct Operations expenses increased by $2.1 million from 2008 to 2009 primarily due to higher personnel and labor expenses, increased severance and employee relocation costs associated with the reorganization of operations and higher compressor and outside operated properties charges.

Interest Expense, Net

Interest expense, net increased by $22.6 million from 2008 to 2009 primarily due to increased interest expense related to the $492 million principal amount of debt we issued in our July and December 2008 private

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placements. Weighted-average borrowings under our credit facility based on daily balances were approximately $166 million during 2009 compared to approximately $172 million during 2008. The weighted-average effective interest rate on the credit facility decreased to approximately 4.0% during 2009 compared to approximately 4.8% during 2008.

Income Tax Expense

Income tax expense decreased by $49.4 million due to a decrease in our pre-tax income. The effective tax rates for 2009 and 2008 were 33.6% and 37.0%, respectively. The decrease in the effective tax rate is primarily due to an overall reduction in state deferred tax liabilities and tax benefits associated with foreign tax credits.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

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

The capital markets continue to be volatile with periods of easy access and times with unfavorable conditions. As a result of the volatility in the capital markets and our increased level of borrowings, we may at times experience increased costs associated with future borrowings and debt issuances based on recent financings. At this time, we do not believe our liquidity has been materially affected by market events.

Derivative Instruments and Hedging Activity

Our hedging strategy is designed to reduce the risk of price volatility for our production in the natural gas and crude oil markets. A hedging committee that consists of members of senior management oversees our hedging activity. Our hedging arrangements apply to only a portion of our production and provide only partial price protection. These hedging arrangements limit the benefit to us of increases in prices, but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the 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 derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. Our credit agreement restricts our ability to enter into commodity hedges other than to hedge or mitigate risks to which we have actual or projected exposure or as permitted under our risk management policies and not subjecting us to material speculative risks. As of December 31, 2010, we had 11 derivative contracts open: four natural gas price swap arrangements, six natural gas basis swaps arrangements and one crude oil price collar arrangement. During 2010, we entered into a total of six new derivative contracts including one crude oil swap contract for 2010, four natural gas swap contracts for 2011 and one crude oil collar contract for 2011.

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

Commodity and Derivative Type

Weighted-Average

Contract Price

Volume

Contract Period

Net Unrealized
Gain / (Loss)
(In thousands)

Derivatives Designated as Hedging Instruments

Natural Gas Swaps

$6.24 per Mcf

12,909 Mmcf

January - December 2011

18,669

Crude Oil Collars

$93.25 Ceiling /$80.00

Floor per Bbl

365 Mbbl

January - December 2011

(1,743

)

16,926

Derivatives Not Designated as Hedging Instruments

Natural Gas Basis Swaps

$(0.27) per Mcf

16,123 Mmcf

January - December 2012

(2,180

)

14,746

The amounts set forth under the net unrealized gain / (loss) column in the tables above represent our total unrealized derivative position at December 31, 2010 and include 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.

From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These cash flow hedges are not held for trading purposes. Under these price swaps, 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.

During 2010, natural gas price swaps covered 35.9 Bcf, or 29%, of our 2010 gas production at an average price of $9.30 per Mcf. We had two crude oil price swaps covering 730 Mbbl, or 90%, of our 2010 oil production at an average price of $104.25 per Bbl.

During 2010, we also entered into crude oil swaps to hedge our price exposure on our 2010 production, natural gas swaps to hedge our price exposure on our 2011 production and crude oil price collars to hedge our price exposure on our 2011 production. In addition, we also have natural gas basis swaps covering a portion of anticipated 2012 production, which do not qualify for hedge accounting.

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 Montreal, JPMorgan, Bank of America and BNP Paribas.

The preceding paragraphs contain forward-looking information concerning future production and projected gains and losses, which may be impacted both by production and by changes in the future market prices of energy commodities. See “Forward-Looking Information” for further details.

Fair Market Value of Financial Instruments

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

- 52 -

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

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

December 31, 2010

December 31, 2009

(In thousands)

Carrying
Amount

Estimated
Fair Value

Carrying
Amount

Estimated
Fair Value

Long-Term Debt

975,000

1,100,830

805,000

863,559

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ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Report of Independent Registered Public Accounting Firm		55
Consolidated Statement of Operations for the Years Ended December 31, 2010, 2009 and 2008		56
Consolidated Balance Sheet at December 31, 2010 and 2009		57
Consolidated Statement of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		58
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008		59
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008		60
Notes to the Consolidated Financial Statements		61
Supplemental Oil and Gas Information (Unaudited)		105
Quarterly Financial Information (Unaudited)		110

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, stockholders’ equity, comprehensive income 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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 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, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2011

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS


	Year Ended December 31,
(In thousands, except per share amounts)	2010		2009			2008
OPERATING REVENUES
Natural Gas	$	694,577	$	729,734		$	758,755
Brokered Natural Gas		65,281		75,283			114,220
Crude Oil and Condensate		79,091		69,936			69,711
Other		5,086		4,323			3,105

		844,035		879,276			945,791
OPERATING EXPENSES
Brokered Natural Gas Cost		56,466		67,030			100,449
Direct Operations—Field and Pipeline		99,642		93,985			91,839
Taxes Other Than Income		37,894		44,649			66,540
Exploration		42,725		50,784			31,200
Depreciation, Depletion and Amortization		327,083		251,260			226,915
Impairment of Oil & Gas Properties and Other Assets		40,903		17,622			35,700
General and Administrative		79,177		68,374			74,185

		683,890		593,704			626,828
Gain/(Loss) on Sale of Assets		106,294		(3,303	)		1,143
Gain on Settlement of Dispute		—		—			51,906

INCOME FROM OPERATIONS		266,439		282,269			372,012
Interest Expense and Other		67,941		58,979			36,389

Income Before Income Taxes		198,498		223,290			335,623
Income Tax Expense		95,112		74,947			124,333

NET INCOME	$	103,386	$	148,343		$	211,290

Earnings Per Share
Basic	$	0.99	$	1.43		$	2.10
Diluted	$	0.98	$	1.42		$	2.08
Weighted-Average Common Shares Outstanding
Basic		103,911		103,616			100,737
Diluted		105,195		104,683			101,726
Dividends Per Common Share	$	0.12	$	0.12		$	0.12

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEET


	December 31,			December 31,
(In thousands, except share amounts)	2010			2009
ASSETS
Current Assets
Cash and Cash Equivalents	$	55,949		$	40,158
Accounts Receivable, Net		94,488			80,362
Income Taxes Receivable		—			8,909
Inventories		29,667			27,990
Derivative Instruments		16,926			114,686
Other Current Assets		5,978			9,397

Total Current Assets		203,008			281,502
Properties and Equipment, Net (Successful Efforts Method)		3,762,760			3,358,199
Other Assets		39,263			43,700

	$	4,005,031		$	3,683,401

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	229,981		$	215,588
Income Taxes Payable		25,957			—
Accrued Liabilities		47,897			58,049
Deferred Income Taxes		—			35,104

Total Current Liabilities		303,835			308,741
Pension and Postretirement Benefits		34,053			54,835
Long-Term Debt		975,000			805,000
Deferred Income Taxes		714,953			644,801
Asset Retirement Obligation		72,311			29,676
Other Liabilities		32,179			27,834

Total Liabilities		2,132,331			1,870,887

Commitments and Contingencies (Note 8)
Stockholders’ Equity
Common Stock:
Authorized—240,000,000 Shares of $0.10 Par Value in 2010 and 2009
Issued—104,210,084 Shares and 103,856,447 Shares in 2010 and 2009, respectively		10,421			10,386
Additional Paid-in Capital		720,920			705,569
Retained Earnings		1,148,391			1,057,472
Accumulated Other Comprehensive Income / (Loss)		(3,683	)		42,436
Less Treasury Stock, at Cost: 202,200 Shares in 2010 and 2009, respectively		(3,349	)		(3,349	)

Total Stockholders’ Equity		1,872,700			1,812,514

	$	4,005,031		$	3,683,401

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS


	Year Ended December 31,
(In thousands)	2010			2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	103,386		$	148,343		$	211,290
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		327,083			251,260			226,915
Impairment of Oil & Gas Properties and Other Assets		40,903			17,622			35,700
Deferred Income Tax Expense		61,809			101,815			120,851
(Gain) / Loss on Sale of Assets		(106,294	)		3,303			(1,143	)
Gain on Settlement of Dispute		—			—			(31,706	)
Exploration Expense		11,657			50,784			31,200
Unrealized Loss on Derivatives		226			1,954			—
Amortization of Debt Issuance Cost		3,381			3,635			634
Stock-Based Compensation Expense and Other		15,413			25,924			14,989
Changes in Assets and Liabilities:
Accounts Receivable, Net		(14,125	)		28,725			(3,928	)
Inventories		(1,677	)		17,687			(18,324	)
Other Current Assets		3,675			3,103			10,816
Other Assets and Other Liabilities		6,204			531			6,422
Accounts Payable and Accrued Liabilities		(1,488	)		(27,202	)		3,321
Income Taxes		34,866			358			38,101
Stock-Based Compensation Tax Benefit		(108	)		(13,790	)		(10,691	)

Net Cash Provided by Operating Activities		484,911			614,052			634,447

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(857,251	)		(610,813	)		(848,640	)
Acquisitions		—			(394	)		(605,748	)
Proceeds from Sale of Assets		243,510			80,180			2,099

Net Cash Used in Investing Activities		(613,741	)		(531,027	)		(1,452,289	)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from Debt		525,000			105,000			892,000
Repayments of Debt		(355,000	)		(167,000	)		(375,000	)
Net Proceeds from Sale of Common Stock		801			83			316,230
Stock-Based Compensation Tax Benefit		108			13,790			10,691
Dividends Paid		(12,467	)		(12,432	)		(12,073	)
Capitalized Debt Issuance Costs		(13,821	)		(10,409	)		(4,403	)

Net Cash Provided by / (Used in) Financing Activities		144,621			(70,968	)		827,445

Net Increase in Cash and Cash Equivalents		15,791			12,057			9,603
Cash and Cash Equivalents, Beginning of Period		40,158			28,101			18,498

Cash and Cash Equivalents, End of Period	$	55,949		$	40,158		$	28,101

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

- 58 -

CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


(In thousands, except per share amounts)	Common Shares			Stock Par			Treaury Shares			Treasury Stock			Paid-In Capital			Accumulated Other Comprehensive Income / (Loss)			Retained Earnings			Total
Balance at December 31, 2007		102,681		$	10,268			5,205		$	(85,690	)	$	424,229		$	(894	)	$	722,344		$	1,070,257

Net Income		—			—			—			—			—			—			211,290			211,290
Exercise of Stock Options		328			33			—			—			2,692			—			—			2,725
Retirement of Treasury Stock		(5,003	)		(500	)		(5,003	)		82,341			(81,841	)		—			—			—
Tax Benefit of Stock-Based Compensation		—			—			—			—			10,691			—			—			10,691
Stock Amortization and Vesting		418			42			—			—			6,545			—			—			6,587
Stock Held in Rabbi Trust		64			6			—			—			(3,198	)		—			—			(3,192	)
Stock Issued for Drilling Company Acquisition		70			7			—			—			3,493			—			—			3,500
Issuance of Common Stock		5,003			500			—			—			312,957			—			—			313,457
Cash Dividends at $0.12 per Share		—			—			—			—			—			—			(12,073	)		(12,073	)
Other Comprehensive Income / (Loss)		—			—			—			—			—			187,320			—			187,320

Balance at December 31, 2008		103,561		$	10,356			202		$	(3,349	)	$	675,568		$	186,426		$	921,561		$	1,790,562

Net Income		—			—			—			—			—			—			148,343			148,343
Exercise of Stock Options and
Stock Appreciation Rights		14			2			—			—			53			—			—			55
Tax Benefit of Stock-Based Compensation		—			—			—			—			13,790			—			—			13,790
Stock Amortization and Vesting		281			28			—			—			14,898			—			—			14,926
Sale of Stock Held in Rabbi Trust		—			—			—			—			1,260			—			—			1,260
Cash Dividends at $0.12 per Share		—			—			—			—			—			—			(12,432	)		(12,432	)
Other Comprehensive Income / (Loss)		—			—			—			—			—			(143,990	)		—			(143,990	)

Balance at December 31, 2009		103,856		$	10,386			202		$	(3,349	)	$	705,569		$	42,436		$	1,057,472		$	1,812,514

Net Income		—			—			—			—			—			—			103,386			103,386
Exercise of Stock Options and
Stock Appreciation Rights		39			4			—			—			766			—			—			770
Tax Benefit of Stock-Based Compensation		—			—			—			—			108			—			—			108
Stock Amortization and Vesting		315			31			—			—			12,899			—			—			12,930
Sale of Stock Held in Rabbi Trust		—			—			—			—			1,578			—			—			1,578
Cash Dividends at $0.12 per Share		—			—			—			—			—			—			(12,467	)		(12,467	)
Other Comprehensive Income / (Loss)		—			—			—			—			—			(46,119	)		—			(46,119	)

Balance at December 31, 2010		104,210		$	10,421			202		$	(3,349	)	$	720,920		$	(3,683	)	$	1,148,391		$	1,872,700

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME


	Year Ended December 31,
(In thousands)	2010					2009						2008
Net Income			$	103,386					$	148,343					$	211,290

Other Comprehensive Income / (Loss), net of taxes:
Reclassification Adjustment for Settled Contracts, net of taxes of $65,734, $147,048 and $4,844, respectively				(107,256	)					(247,979	)					(8,177	)
Changes in Fair Value of Hedge Positions, net of taxes of $(29,777), $(57,303) and $(134,259), respectively				45,878						96,783						226,692
Defined Benefit Pension and Postretirement Plans:
Net Gain / (Loss) Arising During the Year, net of taxes of $(3,245), $1,773 and $10,445, respectively	$	5,693				$	(3,009	)				$	(17,629	)
Effect of Plan Termination and Amendment, net of taxes of $(310), $0 and $0, respectively		506					—						—
Settlement, net of taxes of $(1,528), $0 and $0, respectively		2,493					—						—
Amortization of Net Obligation at Transition, net of taxes of $(240), $(236) and $(234), respectively		392					396						398
Amortization of Prior Service Cost, net of taxes of $(217), $(267) and $(373), respectively		355					450						630
Amortization of Net Loss, net of taxes of $(3,548), $(1,432) and $(603), respectively		5,788		15,227			2,422			259			1,020			(15,581	)

Foreign Currency Translation Adjustment, net of taxes of $(20), $(4,116) and $9,292, respectively				32						6,947						(15,614	)

Total Other Comprehensive Income / (Loss)				(46,119	)					(143,990	)					187,320

Comprehensive Income			$	57,267					$	4,353					$	398,610

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

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CABOT OIL & GAS CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Nature of Operations

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

Certain reclassifications have been made to prior year statement to conform with current year presentation. These reclassifications have no impact on net income.

In 2009, the Company reorganized its operations by combining the Rocky Mountain and Appalachian areas to form the North region and by combining the Anadarko Basin with its Texas and Louisiana areas to form the South region. Additionally, the Company exited Canada through the sale of its properties in April 2009. Prior to the third quarter of 2009, the Company presented the geographic areas as East, Gulf Coast, West and Canada.

The consolidated financial statements contain the accounts of the Company and its subsidiaries after eliminating all significant intercompany balances and transactions.

Recently Adopted Accounting Standards

In February 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2010-09, “Subsequent Events,” which amends Accounting Standards Codification (ASC) 855 to eliminate the requirement to disclose the date through which management has evaluated subsequent events in the financial statements. ASU No. 2010-09 was effective upon issuance and its adoption had no impact on the Company’s financial position, results of operations or cash flows.

Cash and Cash Equivalents

The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents were primarily concentrated in one financial institution at December 31, 2010 and 2009. The Company periodically assesses the financial condition of these institutions and considers any possible credit risk to be minimal.

Inventories

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

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Natural gas gathering and pipeline operations normally include imbalance arrangements with the pipeline. The volumes of natural gas due to or from the Company under imbalance arrangements are recorded at actual selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net pipeline imbalance is included in inventory in the Consolidated Balance Sheet.

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 basis. The allowance for doubtful accounts, which is netted against Accounts Receivable in the Consolidated Balance Sheet, was $4.1 million and $3.6 million at December 31, 2010 and 2009, respectively.

Accounts Payable

This account may include credit balances from outstanding checks in zero balance cash accounts. These credit balances are referred to as book overdrafts and are included as a component of Accounts Payable on the Consolidated Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in Accounts Payable at December 31, 2010 and 2009 as sufficient cash was available for offset.

Properties and Equipment

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

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. The determination is based on a process which relies on interpretations of available geologic, geophysical, and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. If a well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If an exploratory well requires a major capital expenditure before production 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 the additional exploratory wells is under way or firmly planned for the near future. If drilling in the area is not under way or firmly planned, or if the well has not found a commercially producible quantity of reserves, the exploratory well is assumed to be impaired, and its costs are charged to exploration expense.

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

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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 the impairment of its oil and gas properties and other assets 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 crude oil and natural gas prices, operating costs and anticipated production from proved reserves 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 oil. During 2010, 2009 and 2008, the Company recorded total impairments of $40.9 million, $17.6 million and $31.3 million (excluding the impairment of $4.4 million of goodwill), respectively.

Costs attributable to the Company’s unproved properties are not subject to the impairment analysis described above; however, a portion of the costs associated with such properties is subject to amortization based on past drilling and development experience and average property lives. Average property lives are determined on a geographical basis and based on the estimated life of unproved property leasehold rights.

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 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, 2010, 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 within Depreciation, Depletion and Amortization expense on the Company’s Consolidated Statement of Operations.

Risk Management Activities

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

When the designated item associated with a derivative instrument matures or is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to

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occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge.

Effective January 1, 2009, the Company adopted the amended disclosure requirements prescribed in ASC 815, “Derivatives and Hedging.”

Revenue Recognition

Gas Imbalance

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

Brokered Natural Gas Margin

The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses in accordance with ASC 605-45, “Revenue Recognition: Principle Agent Considerations”. 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 takes title to the natural gas purchased or sold. The Company realized $8.8 million, $8.3 million and $13.8 million of brokered natural gas margin in 2010, 2009 and 2008, respectively.

Natural Gas Measurement

The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.

Income Taxes

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

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

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

Stock-Based Compensation

The Company accounts for stock-based compensation under a fair value based method of accounting prescribed under ASC 718. 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 the fair value, either a binomial or Black-Scholes valuation model may be used. Stock-based compensation cost for all types of awards is included in General and Administrative Expense in the Consolidated Statement of Operations.

The tax benefit for stock-based compensation is included as both a cash inflow from financing activities and a cash outflow from operating activities in the Consolidated Statement of Cash Flows. In accordance with ASC 718, the Company recognizes a tax benefit only to the extent it reduces the Company’s income taxes payable. For the years ended December 31, 2010, 2009 and 2008, the Company realized tax benefits of $0.1 million, $13.8 million and $10.7 million, respectively.

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.

Market Risk

The Company’s primary market risk is exposure to oil and natural gas prices. Realized prices are mainly driven by worldwide prices for oil and spot market prices for North American natural gas production. Commodity prices are volatile and unpredictable.

The capital markets continue to be volatile with periods of easy access and times with unfavorable conditions. As a result of the volatility in the capital markets and the Company’s increased level of borrowings, it may a times experience increased costs associated with future borrowings and debt issuances based on recent financings. At this time, the Company does not believe its liquidity has been materially affected by market events.

Credit 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 2010, one customer accounted for approximately 11% of the Company’s total sales. In 2009, two customers accounted for approximately 13% and 11%, respectively, of the Company’s total sales. In 2008, one customer accounted for approximately 16% of the Company’s total sales.

Use of Estimates

In preparing financial statements, the Company follows generally accepted accounting principles. These principles require management to make estimates and assumptions that affect the reported amounts of assets and

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liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved natural gas, natural gas liquids and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties, natural gas, natural gas liquids and crude oil revenues and expenses, current values of derivative instruments, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, asset retirement obligations, pension and postretirement obligations, stock-based compensation and deferred income taxes. Actual results could differ from those estimates.

2. Properties and Equipment, Net

Properties and equipment, net are comprised of the following:


	December 31,
(In thousands)	2010			2009
Proved Oil and Gas Properties	$	4,794,650		$	4,118,005
Unproved Oil and Gas Properties		490,181			423,373
Gathering and Pipeline Systems		237,043			294,755
Land, Building and Other Equipment		86,248			77,474

		5,608,122			4,913,607
Accumulated Depreciation, Depletion and Amortization		(1,845,362	)		(1,555,408	)

	$	3,762,760		$	3,358,199

The following table reflects the net changes in capitalized exploratory well costs during 2010, 2009 and 2008.


	December 31,
(In thousands)	2010			2009			2008
Beginning balance at January 1	$	4,179		$	5,990		$	2,161
Additions to capitalized exploratory well costs pending the determination of proved reserves		4,285			4,179			5,990
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(4,148	)		(762	)		(1,259	)
Capitalized exploratory well costs charged to expense		(31	)		(5,228	)		(902	)

Ending balance at December 31	$	4,285		$	4,179		$	5,990

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of wells for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:


	December 31,
(In thousands)	2010		2009		2008
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	4,285	$	4,179	$	5,990
Capitalized exploratory well costs that have been capitalized for a period greater than one year		—		—		—

Balance at December 31	$	4,285	$	4,179	$	5,990

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At December 31, 2010, 2009 and 2008, the Company did not have any projects that had exploratory well costs that were capitalized for a period of greater than one year after drilling.

In November 2010, the Company recorded an impairment of $5.1 million related to drilling and service equipment that was primarily used in drilling our West Virginia properties. The impairment was a result of decreased activity in West Virginia and the decision to sell the underlying assets. These assets were reduced to fair value of approximately $4.0 million. Fair value was determined using the market approach which considered broker quotes from market participants in the oil field services sector. The estimate was based on significant inputs that were not observable in the market and are considered to be Level 3 inputs as defined in ASC 820.

In September 2010, the Company recorded a $35.8 million impairment of oil and gas properties due to continued price declines and limited activity in two south Texas fields. These fields were reduced to a fair value of approximately $15.4 million using discounted future cash flows.

During 2009, the Company recorded $17.6 million of impairments of oil and gas properties. The Company recorded an impairment of $12.0 million in the Fossil Federal field in San Miguel County, Colorado in the North region resulting from lower well performance and $5.6 million in the Beaurline field in Hidalgo County, Texas in the South region resulting from lower well performance. These fields were reduced to fair value of approximately $8.9 million using discounted future cash flows.

The fair value of the impaired fields was based on significant inputs that were not observable in the market and are considered to be level 3 inputs as defined in ASC 820. Refer to Note 14 for more information and a description of fair value hierarchy. Key assumptions include (1) oil and natural gas 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 production costs and (4) risk adjusted discount rates (14% at September 30, 2010 and 16% at December 31, 2009, respectively).

During 2008, the Company recorded an impairment of approximately $3.0 million in the Corral Creek field in Washakie County, Wyoming in the North region resulting from lower than expected performance from the two well field and $28.3 million in the Trawick field in Rusk County, Texas in the South region resulting from a decline in natural gas prices and higher well costs.

During 2010, 2009 and 2008, amortization of the Company’s unproved properties were $47.6 million, $30.0 million and $41.5 million, respectively and are included in Depreciation, Depletion, and Amortization in the Consolidated Statement of Operations. Included in 2008 amortization was $17.0 million related to three exploratory oil and gas prospects located in Mississippi, Montana and North Dakota that were abandoned. These prospects were abandoned as a result of the significant decline in commodity prices in the fourth quarter of 2008 and the Company’s change in exploration plans for these prospects.

In April 2008, the Company acquired a small oilfield services business for total consideration of $21.6 million, comprised of the conversion of a $15.6 million note receivable, the issuance of 70,168 shares of Company common stock, and the payment of $2.5 million in cash. The transaction was accounted for as a business combination, and the Company recorded approximately $4.4 million of goodwill. In December 2008, the Company fully impaired the goodwill due to the impact of the broad economic downturn and the related reductions in future drilling programs.

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East Texas Property Acquisition

On August 15, 2008, the Company completed the acquisition of certain producing oil and gas properties located in Panola and Rusk counties, Texas in order to expand its position in the Minden field. Total net cash consideration paid by the Company in the transaction was approximately $604.0 million. The east Texas acquisition was recorded using the purchase method of accounting. Financial results for the period from the closing date on August 15, 2008 to December 31, 2009 are included within the Company’s Consolidated Statements of Operations. The following table presents the unaudited pro forma results of operations for the year ended December 31, 2008, as if the acquisition was made at the beginning of the period. These pro forma results are not necessarily indicative of future results, nor do they purport to represent the actual financial results that would have occurred had the acquisition been in effect for the periods presented.


(In thousands, except per share amounts)	Year Ended December 31, 2008
	(Unaudited)
Revenues	$	1,009,412
Net Income	$	218,290
Earnings Per Share:
Basic	$	2.12
Diluted	$	2.10
Weighted-Average Common Shares Outstanding:
Basic		103,142
Diluted		104,131

Disposition of Assets

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. Under the terms of the purchase and sale agreement, the Company is obligated to construct pipelines to connect certain of its 2010 program wells, complete the construction of the Lathrop compressor station and complete taps into certain pipeline delivery points. The Company expects to complete these obligations in the first half of 2011. The Company also entered into a 25 year firm gathering contract with Williams that requires Williams to complete construction of approximately 32 miles of high pressure pipeline, 65 miles of trunklines in Susquehanna County, and build two compressor stations in the next two years. Additionally, Williams will connect all of the Company’s drilling program wells, which will connect our production to five interstate pipeline delivery options.

In November 2010, the Company sold certain oil and gas properties in the Texas panhandle to Kimbrel Oil Corporation and Millbrae Energy VII, LLC for $11.5 million and recognized a $10.8 million gain on sale of assets.

In July 2010, the Company sold certain oil and gas properties located in Colorado to Patera Oil & Gas LLC for approximately $3.0 million. During the second quarter of 2010, the Company recognized an impairment loss of approximately $5.8 million associated with the sale of these properties. The impairment charge is included in Gain / (Loss) on Sale of Assets in the Consolidated Statement of Operations. Fair value of the impaired properties 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.

In June 2010, the Company sold its Woodford shale prospect located in Oklahoma to Continental Resources, Inc. The Company received approximately $15.9 million in cash proceeds and recognized a $10.3 million gain on sale of assets.

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The Company recognized a $3.3 million aggregate loss on sale of assets for the year ended December 31, 2009. This loss included a loss of approximately $16.0 million primarily related to the sale of the Canadian properties described below and a gain of $12.7 million primarily related to the sale of Thornwood properties in the North region. Cash proceeds of $11.4 million were received from the sale of the Thornwood properties.

In April 2009, the Company sold substantially all of its Canadian properties to a Tourmaline Oil Corporation (Tourmaline). Total consideration received from the sale was $84.4 million, consisting of $63.8 million in cash and $20.6 million in common stock of Tourmaline (see Note 4). The total net book value of the Canadian properties sold was $95.0 million. At December 31, 2008, the Company recorded 40.4 Bcfe of proved reserves (two percent of total proved reserves) related to these properties.

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3. Additional Balance Sheet Information

Certain balance sheet amounts are comprised of the following:


	December 31,
(In thousands)	2010			2009
ACCOUNTS RECEIVABLE, NET
Trade Accounts	$	91,077		$	78,656
Joint Interest Accounts		4,901			3,564
Other Accounts		2,603			1,756

		98,581			83,976
Allowance for Doubtful Accounts		(4,093	)		(3,614	)

	$	94,488		$	80,362

INVENTORIES
Natural Gas in Storage	$	13,371		$	14,434
Tubular Goods and Well Equipment		17,072			14,420
Pipeline Imbalances		(776	)		(864	)

	$	29,667		$	27,990

OTHER CURRENT ASSETS
Drilling Advances	$	2,796		$	3,417
Prepaid Balances		2,925			5,980
Deferred Income Taxes		257			—

	$	5,978		$	9,397

OTHER ASSETS
Rabbi Trust Deferred Compensation Plan	$	15,788		$	10,031
Debt Issuance Cost		22,061			11,621
Other Accounts		1,414			1,412
Investment in Equity Securities		—			20,636

	$	39,263		$	43,700

ACCOUNTS PAYABLE
Trade Accounts	$	27,401		$	17,434
Natural Gas Purchases		3,596			3,558
Royalty and Other Owners		36,034			40,080
Accrued Capital Costs		146,824			141,122
Taxes Other Than Income		2,655			4,267
Drilling Advances		523			864
Wellhead Gas Imbalances		5,142			4,140
Other Accounts		7,806			4,123

	$	229,981		$	215,588

ACCRUED LIABILITIES
Employee Benefits	$	10,790		$	11,222
Pension and Postretirement Benefits		1,688			1,469
Taxes Other Than Income		14,576			22,780
Interest Payable		19,488			20,205
Derivative Contracts		—			425
Other Accounts		1,355			1,948

	$	47,897		$	58,049

OTHER LIABILITIES
Rabbi Trust Deferred Compensation Plan	$	21,600		$	19,087
Derivative Contracts		2,180			1,954
Other Accounts		8,399			6,793

	$	32,179		$	27,834

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4. Investment in Equity Securities Carried at Cost

In April 2009, the Company received three million shares of common stock in Tourmaline as partial proceeds for the sale of substantially all of the Company’s Canadian assets. The common stock was carried at cost of $20.6 million and was included in Other Assets in the Consolidated Balance Sheet. As of December 31, 2009, the Company estimated the fair value of its investment to be $42.8 million based on the common stock value received in a recent private placement of Tourmaline’s common stock. Accordingly, the inputs associated with the fair value of the investment were considered level 3 in the fair value hierarchy.

In November 2010, the Company sold its investment in common stock of Tourmaline 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.

5. Debt and Credit Agreements

The Company’s debt consisted of the following as of:


(In thousands)	December 31, 2010		December 31, 2009
Long-Term Debt
7.33% Weighted-Average Fixed Rate Notes	$	95,000	$	170,000
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		—
Credit Facility		213,000		143,000

	$	975,000	$	805,000

The Company has debt maturities of $75 million due in 2013. No other tranches of debt are due within the next five years.

In June 2010, the Company amended the agreements governing its senior notes to amend the required asset coverage ratio (the present value of the Company’s proved reserves plus working capital to debt) contained in the agreements. The amendments revised the calculation of present value of proved reserves to reflect specified pricing assumptions based on quoted futures prices in lieu of historical realized prices, reduced the limit on proved undeveloped reserves included in the calculation from 35% to 30%, and increased the required ratio to 1.75:1 from 1.50:1. The amendments also provided that for so long as a borrowing base calculation is required under the Company’s credit facility, the calculated indebtedness may not exceed 115% of such borrowing base for this ratio. If such a borrowing base calculation is not required under the credit facility, the Company would no longer be subject to the asset coverage ratio under the agreements, but would instead be required to maintain a ratio of debt to consolidated EBITDAX (as defined) not to exceed 3.0 to 1.0. In conjunction with the amendments, the Company incurred $2.0 million of debt issuance costs which were capitalized and are being amortized over the term of the respective amended agreements in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

7.33% Weighted-Average Fixed Rate Notes

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


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

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The 7.33% weighted-average fixed rate notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments. Those covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) of at least 1.75 to 1.0 (as amended) and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

In December 2010, the Company repaid the $75.0 million outstanding of Tranche 1 prior to the due date. In connection with the early payment the Company was required to pay a make-whole premium of $2.8 million which is included in Interest Expense and Other in the Consolidated Statement of Operations.

6.51% Weighted-Average Fixed Rate Notes

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


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

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

9.78% Notes

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

5.58% Weighted-Average Fixed Rate Notes

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


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

Interest on each series of the 5.58% weighted-average fixed rate notes is payable semi-annually. The Company may prepay all or any portion of the Notes of each series on any date at a price equal to the principal

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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.

Revolving Credit Agreement

In September 2010, the Company amended and restated its revolving credit facility. The credit facility provides for an available credit line of $900 million and contains an accordion feature allowing the Company to increase the available credit line to $1.0 billion, if any one or more of the existing banks or new banks agree to provide such increased commitment amount. The credit facility also provides for the issuance of letters of credit, which would reduce the Company’s borrowing capacity. The amended facility provides for a $1.5 billion borrowing base and matures in September 2015.

In conjunction with entering into the September 2010 amended credit facility, the Company incurred $11.7 million of debt issuance costs, which were capitalized and will be amortized over the term of the amended credit facility. Approximately $6.3 million in unamortized costs associated with the original credit facility, as amended in June 2010, will be amortized over the term of the amended credit facility in accordance with ASC 470-50, “Debt Modifications and Extinguishments.”

The credit facility is unsecured. The available credit line is subject to adjustment from time to time on the basis of (1) the projected present value (as determined by the banks based on the Company’s reserve reports and engineering reports) of estimated future net cash flows from certain proved oil and gas reserves and certain other assets of the Company (the “Borrowing Base”) and (2) the outstanding principal balance of the Company’s senior notes. Under the credit facility, the Borrowing Base is set at $1.5 billion, to be periodically redetermined as described below. While the Company does not expect a reduction in the available credit line, in the event that it is adjusted below the outstanding level of borrowings in connection with scheduled redetermination or due to a termination of hedge positions, the Company has a period of six months to reduce its outstanding debt in equal monthly installments to the adjusted credit line available.

The Borrowing Base is redetermined annually under the terms of the credit facility on April 1 ^st . In addition, either the Company or the banks may request an interim redetermination twice a year in connection with certain acquisitions or sales of oil and gas properties.

Interest rates under the credit facility are based on Euro-Dollars (LIBOR) or Base Rate (Prime) indications, plus a margin. These associated margins increase if the total indebtedness under the credit facility and the Company’s senior notes is greater than 25%, greater than 50%, greater than 75% or greater than 90% of the Borrowing Base, as shown below:


	Debt Percentage
	<25%			³ 25% <50%			³ 50% <75%			³ 75% <90%			³ 90%
Eurodollar Margin		2.000	%		2.250	%		2.500	%		2.750	%		3.000	%
Base Rate Margin		1.125	%		1.375	%		1.625	%		1.875	%		2.125	%

The credit facility provides for a commitment fee on the unused available balance at annual rates of 0.50%.

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

(a)

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

(b)

Maintenance of an asset coverage ratio of the present value of proved reserves plus working capital to debt of 1.75 to 1.0.

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(c)

Maintenance of a current ratio of 1.0 to 1.0.

(d)

Prohibition on the merger or sale of all or substantially all of the Company’s or any subsidiary’s assets to a third party, except under certain limited conditions.

In addition, the 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, 2010 and 2009, borrowings outstanding under the Company’s credit facilities were $213.0 million and $143.0 million, respectively. In addition, the Company had $0.30 million letters of credit outstanding at December 31, 2010.

The Company’s weighted-average effective interest rates for the credit facilities during the years ended December 31, 2010, 2009 and 2008 were approximately 3.8%, 4.0% and 4.8%, respectively. As of December 31, 2010 and 2009, the weighted-average interest rate on the Company’s credit facility was approximately 3.1% and 3.9%, respectively.

6. Employee Benefit Plans

Pension Plan

The Company has a non-contributory, defined benefit pension plan for all full-time employees, referred to as the tax qualified defined benefit pension plan (qualified pension plan). Plan benefits are based primarily on years of service and salary level near retirement. Plan assets are mainly equity securities and fixed income investments. The Company complies with the Employee Retirement Income Security Act (ERISA) of 1974 and Internal Revenue Code limitations when funding the plan.

The Company also has an unfunded non-qualified supplemental pension plan to ensure payments to certain executive officers of amounts to which they would have been entitled under the provisions of the pension plan, but for limitations imposed by federal tax laws, referred to as the supplemental non-qualified pension arrangements (non-qualified pension plan).

Termination and Amendment of Qualified and Non-Qualified Pension Plans

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

Freezing the above plans resulted in a remeasurement of the pension obligations and plan assets as of July 28, 2010. In calculating the remeasurement at the time of the termination, management used a discount rate of 5.25% for the qualified pension plan and 4.5% for the non-qualified pension plan, which was consistent with the Company’s methodology of determining the discount rate for these plans in prior periods. The discount rate was based on a yield curve based on high-quality corporate bonds that could be purchased to settle the pension obligation. Management determined the discount rate by matching this yield curve with the timing and amounts of the expected benefit payments for the Company’s plans.

As a result of these changes to the Company’s qualified and non-qualified pension plans, the Company revised its amortization period for prior service costs and actuarial losses, which are now amortized over 17

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months (from August 2010 to December 2011) to reflect the expected amortization period until final distribution of benefits from each plan. Prior service costs established in each plan prior to freeze were fully recognized in the third quarter of 2010 as a result of the plan freeze. Actuarial losses in the qualified pension plan were previously amortized over 10.6 years and actuarial losses in the non-qualified pension plan were previously amortized over 6 years.

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.

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 during the last three years are as follows:


(In thousands)	2010			2009			2008
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	75,092		$	63,008		$	51,603
Service Cost		2,774			3,443			3,313
Interest Cost		3,700			3,712			3,272
Actuarial Loss		9,265			6,262			5,683
Plan Termination and Amendment		(12,331	)		—			—
Benefits Paid		(14,628	)		(1,333	)		(863	)

Benefit Obligation at End of Year		63,872			75,092			63,008

Change in Plan Assets
Fair Value of Plan Assets at Beginning of Year		53,180			34,295			44,744
Actual Return on Plan Assets		7,095			10,903			(13,682	)
Employer Contributions		15,416			10,136			5,000
Benefits Paid		(14,628	)		(1,333	)		(863	)
Expenses Paid		(985	)		(821	)		(904	)

Fair Value of Plan Assets at End of Year		60,078			53,180			34,295

Funded Status at End of Year	$	(3,794	)	$	(21,912	)	$	(28,713	)

Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet at December 31 consist of the following:


(In thousands)	2010			2009			2008
Current Liabilities	$	(603	)	$	(488	)	$	(245	)
Long-Term Liabilities		(3,191	)		(21,424	)		(28,468	)

	$	(3,794	)	$	(21,912	)	$	(28,713	)

Amounts Recognized in Accumulated Other Comprehensive Income

Amounts recognized in accumulated other comprehensive income at December 31 consist of the following:


(In thousands)	2010		2009		2008
Prior Service Cost	$	1,267	$	92	$	143
Net Actuarial Loss		12,248		32,061		36,373

	$	13,515	$	32,153	$	36,516

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Information for Pension Plans with an Accumulated Benefit Obligation in Excess of Plan Assets


(In thousands)	2010		2009		2008
Projected Benefit Obligation	$	63,872	$	75,092	$	63,008
Accumulated Benefit Obligation	$	63,872	$	61,822	$	48,050
Fair Value of Plan Assets	$	60,078	$	53,180	$	34,295

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


(In thousands)	2010			2009			2008
Components of Net Periodic Benefit Cost
Current Year Service Cost	$	2,774		$	3,443		$	3,313
Interest Cost		3,700			3,712			3,272
Expected Return on Plan Assets		(4,260	)		(2,685	)		(3,535	)
Amortization of Prior Service Cost		572			51			51
Amortization of Net Loss		8,705			3,177			1,175
Plan Termination and Amendment		4,444			—			—

Net Periodic Pension Cost	$	15,935		$	7,698		$	4,276

Other Changes in Qualified Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income
Effect of Plan Termination and Amendment	$	(816	)	$	—		$	—
Settlement		(4,021	)		—			—
Net (Gain) / Loss		(4,523	)		(1,135	)		23,804
Amortization of Net Loss		(8,705	)		(3,335	)		(1,175	)
Amortization of Prior Service Cost		(572	)		—			(51	)

Total Recognized in Other Comprehensive Income	$	(18,637	)	$	(4,470	)	$	22,578

Total Recognized in Net Periodic Benefit Cost and Other Comprehensive Income	$	(2,702	)	$	3,228		$	26,854

The estimated prior service cost and net loss for the qualified pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $1.0 million and $10.9 million, respectively.

The estimated prior service cost and net loss for the defined benefit non-qualified pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year are $0.3 million and $1.3 million, respectively.

Assumptions

Weighted-average assumptions used to determine projected pension benefit obligations at December 31 were as follows:


	2010			2009			2008
Discount Rate		5.25	%		5.75	%		6.00	%
Rate of Compensation Increase		—			4.00	%		4.00	%

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Weighted-average assumptions used to determine net periodic pension costs at December 31 are as follows:


	2010			2009			2008
Discount Rate (January 1 - December 31) ⁽¹⁾		—			5.75	%		5.75	%
Discount Rate (January 1, 2010 - July 31, 2010) ⁽²⁾		5.25	%		—			—
Discount Rate (August 1, 2010 - December 31, 2010) ⁽² ⁾		4.80	%		—			—
Expected Long-Term Return on Plan Assets		8.00	%		8.00	%		8.00	%
Rate of Compensation Increase		—			4.00	%		4.00	%

⁽¹ ⁾	Represents the discount rate used to determine the projected benefit costs for qualified and non-qualified pension plans for 2008 and 2009, respectively.

⁽² ⁾

Represents the discount rate used to determine the net periodic pension costs for qualified and non-qualified pension plans for 2010. 5.25% was used from January 1, 2010 through July 31, 2010. Due to the plan termination and amendments that were effective in July 2010, the discount rate was adjusted for determining the net periodic pension costs for the remainder of the year to 4.8%.

The long-term expected rate of return on plan assets used in 2010, as shown above, is 8.0%. The Company establishes the long-term expected rate of return by developing a forward looking long-term expected rate of return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. One of the plan objectives is that performance of the equity portion of the pension plan exceeds the Standard and Poors’ 500 Index over the long-term. The Company also seeks to achieve a minimum five percent annual real rate of return (above the rate of inflation) on the total portfolio over the long-term. In the Company’s pension calculations, the Company has used 8.0 % as the expected long-term return on plan assets for 2010, 2009 and 2008. In order to derive this return, a Monte Carlo simulation was run using 5,000 simulations based upon the Company’s actual asset allocation and liability duration, which has been determined to be approximately 15 years. This model uses historical data for the period of 1926-2007 for stocks, bonds and cash to determine the best estimate range of future returns. The median rate of return, or return that the Company expects to achieve over 50% of the time, is approximately 9%. The Company expects to achieve at a minimum approximately 7% annual real rate of return on the total portfolio over the long-term at least 75% of the time. The Company believes that the 8% chosen is a reasonable estimate based on its actual results.

Plan Assets

The Company’s pension plan assets were accounted for at fair value and are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Each portfolio uses independent pricing services approved by the Trustee to value the Company’s investments. All common/collective trust funds are managed by the Trustee. Refer to Note 14 for more information and a description of the fair value hierarchy.

The Company’s investments in equity securities for which market quotations are readily available are valued at the last reported sale price or official closing price as reported by an independent pricing service on the primary market or exchange on which they are traded.

The Company’s investment in debt securities are valued based on quotations received from dealers who transact in markets with such securities or by independent pricing services. For corporate bonds, bank notes, floating rate loans, foreign government and government agency obligations, municipal securities, preferred securities, supranational obligations, U.S. government and government agency obligations pricing services generally utilize matrix pricing which considers yield or price of bonds of comparable quality, coupon, maturity and type as well as dealer supplied prices.

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At December 31, 2010 and 2009, the non-qualified pension plan did not have plan assets. The fair value of the plan assets of the Company’s qualified pension plan at December 31, 2010 and 2009 by asset category are as follows:


(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, 2010
Asset Category
Cash	$	1,201	$	—	$	—	$	1,201
Equity securities:
Domestic:
Large-cap		—		17,578		—		17,578
Small-cap		—		3,072		—		3,072
Emerging Markets		—		1,817		—		1,817
Growth		—		3,623		—		3,623
International:
Diversified		—		10,204		—		10,204
Small-cap		—		1,232		—		1,232
Debt securities		—		21,351		—		21,351

	$	1,201	$	58,877	$	—	$	60,078


(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, 2009
Asset Category
Cash	$	1,486	$	—	$	—	$	1,486
Equity securities:
Domestic:
Large-cap		—		13,070		—		13,070
Small-cap		—		2,731		—		2,731
Growth		—		4,544		—		4,544
International:
Diversified		—		9,623		—		9,623
Small-cap		—		2,140		—		2,140
Debt securities		—		19,586		—		19,586

	$	1,486	$	51,694	$	—	$	53,180

The Company’s investment strategy for the pension benefit plan assets is to remain fully invested in the market until the final determination for the plan termination is complete. The Company will continue to target a portfolio of assets utilizing equity securities, debt securities and cash equivalents that are within a range of approximately 50% to 80% for equity securities and approximately 20% to 40% for fixed income securities.

Cash Flows

Employer Contributions

The funding levels of the pension and postretirement benefit plans (described below) are in compliance with standards set by applicable law or regulation. The Company did not have any required minimum funding obligations for its qualified pension plan in 2010; however, it chose to fund $10.0 million into the qualified pension plan. In 2011, the Company does not have any required minimum funding obligations for the qualified plan. Currently, management has not determined if any additional discretionary funding will be made in 2011.

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The Company previously disclosed in its financial statements for the year ended December 31, 2009 that it expected to contribute $0.5 million to its non-qualified pension plan in 2010. During 2010, the Company contributed $5.4 million to its non-qualified pension plan primarily due to settlements during the year.

Estimated Future Benefit Payments

As a result of the termination of the qualified and non-qualified pension plans, the Company expects to make a final distribution of benefits from each plan in late 2011 or early 2012.

Postretirement Benefits Other than Pensions

In addition to providing pension benefits, 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. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 257 retirees and their dependents at the end of 2010 and 251 retirees and their dependents at the end of 2009.

When the Company adopted ASC 715-60, “Compensation—Retirement Benefits—Defined Benefit Plans—Other Postretirement” in 1992, it began amortizing the $16.9 million accumulated postretirement benefit, known as the transition obligation, over a period of 20 years, or $0.8 million per year which is included in the annual expense of the plan. Included in the transition obligation are the effects of plan amendments during 1996, 2000 and 2004. As a result of subsequent updates to the requirements for accounting for Defined Benefit Plans codified in ASC 715-20, “Compensation—Retirement Benefits—Defined Benefit Plans—General,” the remaining unamortized balance at December 31, 2006 of $3.2 million is now recognized in accumulated other comprehensive income. Additionally, a portion of this amount will be amortized and reclassified from the balance sheet to the income statement as expense each year.

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 during the last three years, as well as the funded status at the end of the last three years is as follows:


(In thousands)	2010			2009			2008
Change in Benefit Obligation
Benefit Obligation at Beginning of Year	$	34,392		$	26,888		$	20,846
Service Cost		1,265			1,279			1,083
Interest Cost		1,696			1,594			1,380
Actuarial Loss		(4,415	)		5,917			4,270
Benefits Paid		(991	)		(1,286	)		(691	)

Benefit Obligation at End of Year	$	31,947		$	34,392		$	26,888

Change in Plan Assets
Fair Value of Plan Assets at End of Year		N/A			N/A			N/A

Funded Status at End of Year	$	(31,947	)	$	(34,392	)	$	(26,888	)

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Amounts Recognized in the Balance Sheet

Amounts recognized in the balance sheet at December 31 consist of the following:


(In thousands)	2010			2009			2008
Current Liabilities	$	(1,085	)	$	(981	)	$	(642	)
Long-Term Liabilities		(30,862	)		(33,411	)		(26,246	)

	$	(31,947	)	$	(34,392	)	$	(26,888	)

Amounts Recognized in Accumulated Other Comprehensive Income

Amounts recognized in accumulated other comprehensive income at December 31 consist of the following:


(In thousands)	2010		2009		2008
Transition Obligation	$	632	$	1,263	$	1,895
Prior Service Cost		—		—		666
Net Actuarial Loss		8,408		13,455		8,214

	$	9,040	$	14,718	$	10,775

The estimated net obligation at transition and net loss for the defined benefit postretirement plan that will be amortized from accumulated other comprehensive income into net periodic postretirement cost over the next fiscal year are $0.6 million and $0.6 million, respectively.

Components of Net Periodic Benefit Cost


(In thousands)	2010			2009			2008
Components of Net Periodic Postretirement Benefit Cost
Current Year Service Cost	$	1,265		$	1,279		$	1,083
Interest Cost		1,696			1,594			1,380
Amortization of Prior Service Cost		—			666			952
Amortization of Net Obligation at Transition		632			632			632
Amortization of Net Loss		631			676			448

Net Periodic Postretirement Cost	$	4,224		$	4,847		$	4,495

Other Changes in Benefit Obligations Recognized in Other Comprehensive Income
Net (Gain) / Loss	$	(4,415	)	$	5,917		$	4,270
Amortization of Prior Service Cost		—			(666	)		(952	)
Amortization of Net Obligation at Transition		(632	)		(632	)		(632	)
Amortization of Net Loss		(631	)		(676	)		(448	)

Total Recognized in Other Comprehensive Income		(5,678	)		3,943			2,238

Total Recognized in Qualified Net Periodic Benefit Cost and Other Comprehensive Income	$	(1,454	)	$	8,790		$	6,733

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Assumptions

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


	2010			2009			2008
Discount Rate ⁽¹⁾		5.75	%		5.75	%		5.75	%
Health Care Cost Trend Rate for Medical Benefits Assumed for Next Year		9.00	%		10.00	%		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			2013

⁽¹⁾	Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2010, 2009 and 2008, respectively, the beginning of year discount rates of 5.75%, 5.75% and 6.0% were used.

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

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


(In thousands)	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total of service and interest cost	$	516	$	(419	)
Effect on postretirement benefit obligation		4,727		(3,893	)

Cash Flows

Contributions

The Company expects to contribute approximately $1.1 million to the postretirement benefit plan in 2011.

Estimated Future Benefit Payments

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


(In thousands)
2011	$	1,116
2012		1,195
2013		1,384
2014		1,588
2015		1,717
Years 2016 - 2020		11,119

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit

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plans that provide a benefit that is at least actuarially equivalent to certain Medicare benefits. In accordance with accounting and disclosure requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 codified in ASC 715-60, any measures of the accumulated plan benefit obligation or net periodic postretirement benefit cost in the financial statements or accompanying notes do not reflect the effects of the Act on the Company’s plan. As amended by the Company on January 1, 2006, the postretirement benefit plan excludes prescription drug benefits to participants age 65 and older. Due to this amendment, there was no impact on operating results, financial position or cash flows of the Company.

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 charged to expense plan contributions of $2.2 million, $2.2 million and $2.2 million in 2010, 2009 and 2008, respectively. The Company matches employee contributions dollar-for-dollar on the first six percent of an employee’s pretax earnings. The Company’s common stock is an investment option within the SIP.

In July 2010, the Company amended the SIP to provide for discretionary profit sharing contributions upon termination of the qualified pension plan effective September 30, 2010. The Company presently makes a discretionary profit-sharing contribution to this plan in an amount equal to 9% of an eligible plan participant’s salary and bonus. The Company charged to expense plan contributions of $0.8 million in 2010.

Deferred Compensation Plan

In 1998, the Company established a Deferred Compensation Plan which was available to officers of the Company 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 of determining contributions to the Deferred Compensation Plan and does not impose limitations on the amount of contributions to the Deferred Compensation Plan. Effective October 1, 2010, the Company amended the Deferred Compensation Plan to broaden the group of eligible employees who participate in the plan beyond the officers of the Company. Under this amendment, the Company may designate any member of the Company’s management group as a participant in the Deferred Compensation Plan and may further designate whether such a participant is eligible to make deferral elections from their compensation. At the present time, the Company anticipates making such 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 full Company matching contribution under the SIP. The Deferred Compensation Plan was also amended to provide that the Company would credit the accounts of participants who had entered into supplemental employee retirement plan agreements with the Company in an amount equal to which such participant would have been entitled under the terms of the supplemental employee retirement plan agreement in effect between the Company and the participant as of September 29, 2010, if the participant had terminated employment on September 30, 2010. This amendment also placed restrictions on the payment of these amounts in order to comply with Section 409A of the Internal Revenue Code.

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.

The participants direct the deemed investment of amounts credited to their accounts under the Deferred Compensation Plan. The trust assets are invested in either mutual funds that cover the investment spectrum from equity to money market, or may include holdings of the Company’s common stock, which is funded by the issuance of shares to the trust. The mutual funds are publicly traded and have market prices that are readily available. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets, excluding the Company’s common stock, was $15.8 million and $10.0 million at December 31, 2010 and 2009, respectively, and is included within Other Assets in the Consolidated

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Balance Sheet. Related liabilities, including the Company’s common stock, totaled $21.6 million and $19.1 million at December 31, 2010 and 2009, respectively, and are included within Other Liabilities in the Consolidated Balance Sheet. With the exception of the Company’s common stock, there is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets because the changes in market value of the trust assets are offset completely by changes in the value of the liability, which represents trust assets belonging to plan participants.

The Company’s common stock held in the rabbi trust is recorded at the market value on the date of deferral, which totaled $6.6 million and $8.2 million at December 31, 2010 and 2009, respectively and is included within Additional Paid-in Capital in Stockholders’ Equity in the Consolidated Balance Sheet. As of December 31, 2010, 174,318 shares of the Company’s stock representing vested performance share awards were deferred into the rabbi trust. During 2010, an increase to the rabbi trust deferred compensation liability of $2.5 million was recognized, representing an increase of $4.1 million related to an increase in the closing price of all shares from December 31, 2009 to December 31, 2010 offset by a reduction in the liability due to shares that were sold out of the rabbi trust totaling $1.6 million. 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 $109,196 in 2010, $0 in 2009 and less than $20,000 in 2008.

7. Income Taxes

Income tax expense is summarized as follows:


	Year Ended December 31,
(In thousands)	2010		2009			2008
Current
Federal	$	29,879	$	(26,323	)	$	2,631
State		3,424		(545	)		30

Total		33,303		(26,868	)		2,661

Deferred
Federal		37,981		100,896			116,127
State		23,828		919			5,545

Total		61,809		101,815			121,672

Total Income Tax Expense	$	95,112	$	74,947		$	124,333

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


	Year Ended December 31,
(Dollars in thousands)	2010			2009			2008
Statutory Federal Income Tax Rate		35	%		35	%		35	%
Computed “Expected” Federal Income Tax	$	69,475		$	78,153		$	117,468
State Income Tax, Net of Federal Income Tax Benefit		6,638			4,476			6,581
Deferred Tax Adjustment Related to Change in Overall State Tax Rate		18,973			(3,925	)		(1,453	)
Sale of Foreign Assets		—			(1,656	)		—
Other, Net		26			(2,101	)		1,737

Total Income Tax Expense	$	95,112		$	74,947		$	124,333

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


	Year Ended December 31,
(In thousands)	2010		2009
Deferred Tax Liabilities
Property, Plant and Equipment	$	925,397	$	765,811
Hedging Liabilities / Receivables		6,419		42,243
Prepaid Expenses and Other		6,654		1,635

Total		938,470		809,689

Deferred Tax Assets
Alternative Minimum Tax Credit		62,105		38,835
Net Operating Loss		95,102		31,111
Foreign Tax Credits		6,354		1,738
Pension and Other Post-Retirement Benefits		13,342		20,914
Items Accrued for Financial Reporting Purposes and Other		46,871		37,186

Total		223,774		129,784

Net Deferred Tax Liabilities	$	714,696	$	679,905

As of December 31, 2010, The Company had alternative minimum tax credit carryforwards of $62.1 million which do not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the alternative minimum tax in any such year. The Company also had net operating loss carryforwards of $288.5 million for state reporting purposes, the majority of which will expire between 2016 and 2030. It is expected that these deferred tax benefits will be utilized prior to their expiration.

Uncertain Tax Positions

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


	Year Ended December 31,
(In thousands)	2010			2009		2008
Unrecognized tax benefit balance at beginning of year	$	500		$	500	$	2,425
Additions based on tax provisions related to the current year		—			—		—
Additions for tax positions of prior years					—		—
Reductions for tax positions of prior years		(500	)		—		(1,925	)
Settlements		—			—		—

Unrecognized tax benefit balance at end of year	$	—		$	500	$	500

During 2010, unrecognized tax benefits were reduced by $0.5 million as a result of the completion of Internal Revenue Service (IRS) Joint Committee on Taxation review of the 2005-2008 tax years that were under audit by the IRS. This reduction did not materially affect the effective tax rate. During 2008, the Company executed a final settlement agreement with the IRS that reduced unrecognized tax benefits by $1.9 million. This reduction did not affect the effective tax rate.

As of December 31, 2010, the Company did not have any uncertain tax positions reported in the Consolidated Balance Sheet.

The Company files income tax returns in the U.S. federal jurisdiction, various states and Canada. The Company is no longer subject to examinations by state authorities before 2005. The Company is not currently under examination by the IRS.

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8. Commitments and Contingencies

Firm Gas Transportation Agreements

The Company has incurred, and will incur over the next several years, demand charges on firm gas transportation agreements. These agreements provide firm transportation capacity rights on pipeline systems primarily in the North region. The remaining terms on these agreements range from less than one year to approximately 20 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company. If the Company does not utilize the capacity, it can release it to others, thus reducing its potential liability. The agreements that the Company previously had in place on pipeline systems in Canada were transferred in April 2009 to the buyer in connection with the sale of the Company’s Canadian properties (discussed in Note 2).

During 2010, the Company entered into new firm gas transportation arrangements with third-party pipelines to transport approximately 296 Mmcf/day in the North region. One of the new agreements commenced in the second quarter of 2010 and the remaining new agreements are expected to commence in 2011, which includes the 20 year transportation agreement entered into with Williams in December 2010 (discussed in to Note 2). These new agreements have terms of five to twenty years from the respective commencement dates. Future obligations under firm gas transportation agreements which commenced during 2010 are $78.4 million as of December 31, 2010.

Future obligations under firm gas transportation agreements as of December 31, 2010 are as follows:


(In thousands)
2011	$	32,504
2012		35,684
2013		28,356
2014		28,356
2015		28,356
Thereafter		332,363

	$	485,619

Drilling Rig Commitments

As of December 31, 2010, the Company does not have any outstanding drilling commitments with initial terms greater than one year.

Lease Commitments

The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. Rent expense under these arrangements totaled $18.3 million, $17.4 million and $14.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

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Future minimum rental commitments under non-cancelable leases in effect at December 31, 2010 are as follows:


(In thousands)
2011		5,414
2012		5,133
2013		4,769
2014		4,211
2015		2,631
Thereafter		—

	$	22,158

Contingencies

Environmental Matters

On April 15, 2010, the Company and PaDEP reached agreement on modifications to the Consent Order (First Modified Consent Order). In the First Modified Consent Order, PaDEP and the Company agreed that the Company will provide a permanent source of potable water to 14 households, most of which the Company has already been supplying with water. The Company agreed to plug and abandon three vertical wells in close proximity to two of the households and to bring into compliance a fourth well in the nine square mile area of concern in Susquehanna County. The Company agreed to complete these actions prior to any new well drilling permits being issued for drilling in Pennsylvania, and prior to initiating hydraulic fracturing of seven wells already drilled in the area of concern. The Company also agreed to postpone drilling of new wells in the area of concern until all obligations under the consent orders are fulfilled. In addition, the Company agreed to take certain other actions if requested by PaDEP, which could include the plugging and abandonment of up to 10 additional wells. Under the First Modified Consent Order, the Company paid a $240,000 civil penalty and agreed to pay an additional $30,000 per month until all obligations under the First Modified Consent Order are satisfied.

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As of December 31, 2010, the Company has paid $1.3 million in fines and penalties to the PaDEP paid $0.6 million to two of the affected households and accrued a $3.6 million settlement liability related to this matter which is included in Other Liabilities in the Consolidated Balance Sheet.

Settlement of Dispute

In December 2008, the Company settled a dispute with a third party resulting in the Company recording a gain of $51.9 million. The dispute involved the propriety of possession of the Company’s intellectual property by a third party. The settlement was comprised of $20.2 million in cash paid by the third party to the Company and $31.7 million related to the fair value of unproved property rights transferred by the third party to the Company. The fair market value of the unproved property rights was determined based on observable market costs and conditions over a recent time period. Values were pro-rated by property based on the primary term remaining on the properties.

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9. Asset Retirement Obligation

The following table provides a rollforward of the asset retirement obligation. Liabilities settled include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Liabilities incurred include additions to obligations as well as obligations that were assumed by the Company related to acquired properties. Activity related to the Company’s asset retirement obligation during the year ended December 31, 2010 is as follows:


(In thousands)
Carrying amount of asset retirement obligation at December 31, 2009	$	29,676
Change in estimate		40,443
Liabilities incurred		966
Liabilities settled		(693	)
Accretion expense		1,919

Carrying amount of asset retirement obligation at December 31, 2010	$	72,311

The change in estimate during 2010 is attributable to additional regulatory requirements in east Texas and increased costs for services and equipment to plug and abandon wells in all of our areas of operations.

Accretion expense for the years ended December 31, 2010, 2009 and 2008 was $1.9 million, $1.3 million and $1.2 million, respectively.

10. Supplemental Cash Flow Information

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


	Year Ended December 31,
(In thousands)	2010			2009		2008
Interest	$	64,342		$	56,301	$	23,089
Income Taxes		(1,050	)		27,080		(33,753	)

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. In the first quarter of 2007, the Board of Directors eliminated the automatic award of an option to purchase 30,000 shares of common stock on the date the non-employee directors first join the Board of Directors. In its place, the Board of Directors considers an annual fixed dollar stock award which is competitive with the Company’s peer group. A total of 5,100,000 shares of common stock may be issued under the 2004 Incentive Plan. Under the 2004 Incentive Plan, no more than 1,800,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 3,000,000 shares may be issued pursuant to incentive stock options.

Stock Issuance

On June 20, 2008, the Company entered into an underwriting agreement, pursuant to which the Company sold an aggregate of 5,002,500 shares of common stock at a price to the Company of $62.66 per share. On June 25, 2008, the Company closed the public offering and received $313.5 million in net proceeds, after deducting underwriting discounts and commissions. These net proceeds were used to reduce outstanding

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borrowings under the Company’s revolving credit facility prior to funding a portion of the purchase price of the Company’s east Texas acquisition, which closed in the third quarter of 2008.

Immediately prior to (and in connection with) this issuance, the Company retired 5,002,500 shares of its treasury stock, which had a weighted-average purchase price of $16.46, representing $82.3 million. In accordance with the Company’s policy, the excess of cost of the treasury stock over its par value was charged entirely to additional paid-in capital.

Increase in Authorized Shares

In April 2009, the stockholders of the Company approved an increase in the authorized number of shares of common stock from 120 million to 240 million shares.

Treasury Stock

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

During the year ended December 31, 2010, the Company did not repurchase any shares of common stock. Since the authorization date, the Company has repurchased 5,204,700 shares of the 10 million total shares authorized for a total cost of approximately $85.7 million. The repurchased shares were held as treasury stock. No treasury shares have been delivered or sold by the Company subsequent to the repurchase. In connection with the June 2008 common stock issuance, the Company retired 5,002,500 shares of its treasury stock as discussed above under the heading “Stock Issuance.” As of December 31, 2010, 202,200 shares were held as treasury stock.

Dividend Restrictions

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

Expired Purchase Rights Plan

On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of common stock. On December 8, 2000, the rights agreement for the plan was amended and restated to extend the term of the plan to 2010 and to make other changes. At December 31, 2010 and 2009 there were no shares of Junior Preferred Stock issued or outstanding. The rights plan expired on January 21, 2010.

12. Stock-Based Compensation

Compensation expense charged against income for stock-based awards (including the supplemental employee incentive plan) for the years ended December 31, 2010, 2009 and 2008 was $14.4 million, $25.1 million and $34.5 million, respectively, and is included in General and Administrative Expense in the Consolidated Statement of Operations.

The Company did not recognize a tax benefit related to stock-based compensation in 2010 as a result of the tax net operating loss position for the year. For the year ended December 31, 2009, the Company realized a $13.8

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million tax benefit related primarily to the federal tax deduction in excess of book compensation cost for employee stock-based compensation for 2008 and, to a lesser extent, state tax deductions for 2007. For regular federal income tax purposes, the Company was in a net operating loss position in 2008. As the Company carried back net operating losses concurrent with its 2008 tax return filing, the income tax benefit related to stock-based compensation was recorded in 2009. In accordance with ASC 718, the Company is able to recognize this tax benefit only to the extent it reduces the Company’s income taxes payable. For the year ended December 31, 2008, the Company realized a $10.7 million tax benefit related to the 2007 federal tax deduction in excess of book compensation cost related to employee stock-based compensation. Such income tax benefit related to the stock-based compensation was recorded in 2008 as the Company carried back net operating losses concurrent with the 2007 tax return filing. The Company did not recognize a tax benefit related to stock-based compensation in 2007 as a result of the tax net operating loss position for the year. Under ASC 718, the tax benefits resulting from tax deductions in excess of expense are reported as an operating cash outflow and a financing cash inflow. For the years ended December 31, 2010, 2009 and 2008, $0.1 million, $13.8 million and $10.7 million were reported in these two separate line items in the Consolidated Statement of Cash Flows.

Restricted Stock Awards

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

The fair value of restricted stock grants is based on the average of the high and low stock price on the grant date. The maximum contractual term is four years. In accordance with ASC 718, 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 for awards issued after the adoption of ASC 718. The Company used an annual forfeiture rate ranging from 0% to 7.0% based on approximately ten 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, 2010:


Restricted Stock Awards	Shares			Weighted- Average Grant Date Fair Value per Share		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands) ⁽¹⁾
Outstanding at December 31, 2009		185,923		$	34.62
Granted		23,800			34.87
Vested		(46,350	)		32.61
Forfeited		(31,210	)		33.93

Non-vested shares outstanding at December 31, 2010		132,163		$	35.53		1.7	$	5,002

⁽¹⁾	The aggregate intrinsic value of restricted stock awards is calculated by multiplying the closing market price of the Company’s stock on December 31, 2010 by the number of non-vested restricted stock awards outstanding.

As shown in the table above, there were 23,800 shares of restricted stock granted to employees during 2010 with a weighted-average grant date fair value per share of $34.87. During the year ended December 31, 2009, 145,060 shares of restricted stock granted to employees with a weighted-average grant date fair value per share of $34.95. During the year ended December 31, 2008, 13,000 shares of restricted stock were granted to

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employees with a weighted-average grant date fair value per share of $40.93. The total fair value of shares vested during 2010, 2009 and 2008 was $1.5 million, $1.2 million and $6.5 million, respectively.

Compensation expense recorded for all restricted stock awards for the years ended December 31, 2010, 2009 and 2008 was $1.8 million, $1.2 million and $1.5 million, respectively. Included in 2010 restricted stock expense was $1.1 million related to the immediate expensing of shares granted to retirement-eligible employees. Unamortized expense as of December 31, 2010 for all outstanding restricted stock awards was $2.1 million and will be recognized over the next 1.8 years.

Restricted Stock Units

Restricted stock units are granted from time to time to non-employee directors of the Company. 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, 2010:


Restricted Stock Units	Units		Weighted- Average Grant Date Fair Value per Unit		Weighted- Average Remaining Contractual Term (in years) ⁽²⁾		Aggregate Intrinsic Value (in thousands) ⁽¹⁾
Outstanding at December 31, 2009		115,165	$	26.86
Granted and fully vested		26,961		40.07
Issued		—		—
Forfeited		—		—

Outstanding at December 31, 2010		142,126	$	29.37		—	$	5,379

⁽¹⁾	The intrinsic value of restricted stock units is calculated by multiplying the closing market price of the Company’s stock on December 31, 2010 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 below.

As shown in the table above, 26,961 restricted stock units were granted with a weighted-average grant date fair value per share of $40.07 during 2010. During 2009, 33,150 restricted stock units were granted with a weighted-average grant date fair value per share of $22.63. During 2008, 16,565 restricted stock units were granted with a weighted-average grant date fair value per share of $49.17.

The compensation cost, which reflects the total fair value of these units, recorded in 2010 was $1.1 million. Compensation expense recorded during the years ended December 31, 2009 and 2008 for restricted stock units was $0.8 million and $0.8 million, respectively.

Stock Options

Stock option awards are granted 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, 2010, 2009 and 2008, there were no stock options granted.

The Company uses a Black-Scholes model to calculate the fair value of stock options. Compensation cost is recorded based on a graded-vesting schedule as the options vest over a service period of three years, with

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one-third of the award becoming exercisable each year on the anniversary date of the grant. Stock options have a maximum contractual term of five years. No forfeiture rate is assumed for stock options granted to directors due to the forfeiture rate history for these types of awards for this group of individuals. During 2010 there was no compensation expense recorded. Compensation expense recorded for stock options for 2009 was less than $0.1 million and for 2008 was $0.1 million. There was no unamortized expense as of December 31, 2010 for stock options.

The following table is a summary of stock option activity for the years ended December 31, 2010, 2009 and 2008:


	2010					2009					2008
Stock Options	Shares			Weighted- Average Exercise Price		Shares			Weighted- Average Exercise Price		Shares			Weighted- Average Exercise Price
Outstanding at Beginning of Year		50,000		$	23.80		60,500		$	21.69		388,950		$	10.38
Granted		—					—			—		—			—
Exercised		(35,000	)		23.80		(10,500	)		11.66		(328,450	)		8.30
Forfeited or Expired		—			—		—			—		—			—

Outstanding at December 31 ⁽¹⁾		15,000		$	23.80		50,000		$	23.80		60,500		$	21.69

Options Exercisable at December 31 ⁽²⁾		15,000		$	23.80		50,000		$	23.80		40,500		$	20.65

⁽¹⁾

The intrinsic value of a stock option is the amount which the current market value of the underlying stock exceeds the exercise price of the option. The aggregate intrinsic value of options outstanding at December 31, 2010 was $0.2 million. The weighted-average remaining contractual term is less than one year.

⁽²⁾	The aggregate intrinsic value of options exercisable at December 31, 2010 was $0.2 million. The weighted-average remaining contractual term is less than one year.

The total intrinsic value of options exercised during the years ended December 31, 2010, 2009 and 2008 was less than $0.5 million, $0.1 million and $12.2 million, respectively.

Stock Appreciation Rights

Beginning in 2006, the Compensation Committee has granted SARs to employees. These awards allow the employee to receive any intrinsic value over the grant date market price that may result from the price appreciation on a set number of common shares during the contractual term of seven years. All of these awards have graded-vesting features and will vest over a service period of three years, with one-third of the award becoming exercisable each year on the anniversary date of the grant. The Company calculates the fair value using a Black-Scholes model.

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


	Year Ended December 31,
	2010			2009			2008
Weighted-Average Value per Stock Appreciation Rights
Granted During the Period	$	18.96		$	9.35		$	15.18
Assumptions
Stock Price Volatility		52.9	%		50.5	%		34.4	%
Risk Free Rate of Return		2.4	%		1.7	%		2.8	%
Expected Dividend Yield		0.3	%		0.5	%		0.2	%
Expected Term (in years)		5.0			4.5			4.3

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

The following table is a summary of SAR activity for the years ended December 31, 2010, 2009 and 2008:


	2010					2009					2008
Stock Appreciation Rights	Shares			Weighted- Average Exercise Price		Shares			Weighted- Average Exercise Price		Shares		Weighted- Average Exercise Price
Outstanding at Beginning of Year		673,100		$	29.27		491,930		$	32.26		372,800	$	27.08
Granted		79,550			40.53		221,780			22.63		119,130		48.48
Exercised		(17,000	)		27.16		(20,366	)		26.19		—		—
Forfeited or Expired		—					(20,244	)		32.19		—

Outstanding at December 31 ⁽¹⁾		735,650		$	30.54		673,100		$	29.27		491,930	$	32.26

Exercisable at December 31 ⁽²⁾		532,222		$	29.63		354,252		$	28.58		212,790	$	25.72

⁽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, 2010 was $6.8 million. The weighted-average remaining contractual term is 3.5 years.

⁽²⁾	The aggregate intrinsic value of SARs exercisable at December 31, 2010 was $5.3 million. The weighted-average remaining contractual term is 2.8 years.

As shown in the table above, the Compensation Committee granted 79,550 SARs to employees during 2010 with a weighted-average exercise price equal to the grant date market price of $40.53. Compensation expense recorded during the years ended December 31, 2010, 2009 and 2008 for all outstanding SARs was $1.6 million, $1.8 million and $1.7 million, respectively. In 2010, there was no expense related to the immediate expensing of shares granted to retirement-eligible employees. Included in 2009 and 2008 expense was $0.7 million and $0.5 million, respectively, related to the immediate expensing of shares granted to retirement-eligible employees. Unamortized expense as of December 31, 2010 for all outstanding SARs was $0.6 million. The weighted-average period over which this compensation will be recognized is approximately 1.1 years.

Performance Share Awards

During 2010, the Compensation Committee granted three types of performance share awards to employees for a total of 347,170 performance shares. For all performance share awards granted to employees in 2010, an annual forfeiture rate ranging from 0% to 7.0% has been assumed based on the Company’s history for this type of award to various employee groups.

Awards totaling 180,180 performance shares based on performance conditions are earned, or not earned, based on the Company’s internal performance metrics. Fair value is measured based on the average of the high and low stock price of the Company on the grant date and expense is amortized straight-line over the three year period. The grant date per share value of this award was $40.53. These awards represent the right to receive up to 100% of the award in shares of common stock. The actual number of shares issued at the end of the performance period will be determined based on the Company’s performance against three internal performance criteria set by the Company’s Compensation Committee. The performance period for the awards granted in 2010 commenced

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on January 1, 2010 and ends December 31, 2012. An employee will earn one-third of the award granted for each internal performance metric that the Company meets at the end of the performance period. These performance criteria measure the Company’s average production, average finding costs and average reserve replacement over three years. Based on the Company’s probability assessment at December 31, 2010, it is considered probable that these three criteria will be met for all outstanding awards.

The second type of performance share award, totaling 82,520 performance shares based on performance conditions, with a grant date per share value of $40.53, has a three-year graded performance period. Fair value is measured based on the average of the high and low stock price of the Company on the grant date and expense is amortized straight-line over the three year period. On each anniversary date following the date of grant, one-third of the shares are issued, provided that the Company has $100 million or more of operating cash flow for the year preceding the performance period. If the Company does not have $100 million or more of operating cash flow for the year preceding a performance period, then the portion of the performance shares that would have been issued on that date will be forfeited. As of December 31, 2010, it is considered probable that this performance metric will be met.

Awards totaling 84,470 performance shares based on market conditions 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. The performance period for the awards granted in 2010 commenced on January 1, 2010 and ends December 31, 2012. To determine the fair value for awards that are based on the Company’s comparative performance against a peer group (market condition), the equity and liability components are bifurcated. On the grant date, the equity component was valued using a Monte Carlo binomial model and is amortized on a straight-line basis over three years. The liability component is valued at each reporting period by using a Monte Carlo binomial model. Depending on the Company’s performance, employees may receive an aggregate of up to 100% of the fair market value of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash.

The four primary inputs for the Monte Carlo model are the risk-free rate, volatility of returns, correlation in movement of total shareholder return and the expected dividend. An interpolated risk-free rate was generated from the Federal Reserve website for constant maturity treasuries for two and three year bonds (as of the reporting date) set equal to the remaining duration of the performance period. Volatility was set equal to the annualized daily volatility for the remaining duration of the performance period ending on the reporting date. Correlation in movement of total shareholder return was determined based on a correlation matrix that was created which identifies total shareholder return correlations for each pair of companies in the peer group, including the Company. The paired returns in the correlation matrix ranged from approximately 60.48% to approximately 85.65% for the Company and its peer group. The expected dividend is calculated using the total Company annual dividends expected to be paid divided by the closing price of the Company’s stock at the valuation date. Based on these inputs discussed above, a ranking was projected identifying the Company’s rank relative to the peer group for each award period.

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


	Year Ended December 31,
	2010			2009			2008
Weighted-Average Fair Value per Performance Share
Award Granted During the Period	$	13.00		$	17.63		$	41.53
Assumptions
Stock Price Volatility		61.8	%		57.6	%		37.7	%
Risk Free Rate of Return		1.4	%		1.3	%		1.7	%
Expected Dividend Yield		0.3	%		0.5	%		0.2	%

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


	December 31,
	2010		2009
Fair Value per Performance Share Award at the End of the Period	$	0.00 - $6.15	$	14.38 - 16.24
Assumptions
Stock Price Volatility		70.7% - 71.7%		57.7% - 70.8%
Risk Free Rate of Return		0.3% - 0.4%		0.5% - 1.4%
Expected Dividend Yield		0.4%		0.3%

The long-term liability for market condition performance share awards, included in Other Liabilities in the Consolidated Balance Sheet, at December 31, 2010 and 2009 was $0.6 million and $1.1 million, respectively. The short-term liability, included in Accrued Liabilities in the Consolidated Balance Sheet, at December 31, 2010 and 2009 was 2.4 million for both periods.

On December 31, 2010, the performance period ended for two types of performance shares awarded in 2008, including 143,800 shares measured based on internal performance metrics of the Company and 96,680 shares measured based on the Company’s performance against a peer group. For the internal performance metric awards, the calculation of the average of the three years of the Company’s three internal performance metrics was completed in the first quarter of 2011 and was certified by the Compensation Committee in February 2011. As the Company achieved the three internal performance metrics, 100% of the award, valued at $6.9 million based on the average of the high and low stock price on the grant date, was payable in 143,800 shares of common stock. For the peer group awards, due to the ranking of the Company compared to its peers in its predetermined peer group, 75% of the award, valued at $3.0 million based on the Monte Carlo value on the grant date, was payable in 72,512 shares of common stock. The vesting of both types of shares discussed above will be reported in the first quarter of 2011.

The following table is a summary of performance share award activity for the year ended December 31, 2010:


Performance Share Awards	Shares			Weighted- Average Grant Date Fair Value per Share ⁽¹⁾		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value (in thousands) ⁽²⁾
Outstanding at December 31, 2009		1,296,393		$	29.74
Granted		347,170			38.48
Issued and Fully Vested		(410,269	)		32.28
Forfeited		(40,180	)		32.82

Outstanding at December 31, 2010		1,193,114		$	31.31		1.0	$	45,159

⁽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, 2010 by the number of non-vested performance share awards outstanding.

Of the performance shares that vested during 2010 shown in the table above, 92,400 shares were granted in 2007. These shares (valued at $2.8 million) were measured based on the Company’s performance against a peer group and were issued in addition to cash of $1.3 million. A total of 150,100 shares (valued at $5.3 million) measured based on internal performance metrics of the Company were also issued. During 2010, 167,769

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shares vested (valued at $5.1 million) which represents one-third of the three-year graded vesting schedule performance share awards granted in 2009, 2008 and 2007 with a grant date per share value of $22.63, $48.48 and $35.22, respectively.

During the year ended December 31, 2009, 785,350 performance share awards were granted to employees with a weighted-average grant date fair value per share of $21.30. Of the 332,642 performance shares that vested during 2009, 105,800 shares were granted in 2006. These shares (valued at $1.7 million) were measured based on the Company’s performance against a peer group and were issued in addition to cash of $1.8 million. A total of 155,800 shares (valued at $3.8 million) measured based on internal performance metrics of the Company were also issued. During 2009, 60,740 shares vested (valued at $2.5 million) which represents one-third of the three-year graded vesting schedule performance share awards granted in 2008 and 2007 with a grant date per share value of $48.48 and $35.22, respectively. In addition, 10,302 performance shares vested as a result of early vesting schedules for certain employees. These awards met the performance criteria that the Company had positive operating income for 2008 and 2007.

During the year ended December 31, 2008, 383,065 performance share awards were granted with a weighted-average grant date fair value per share of $46.63. Of the 249,990 performance shares that vested during 2008, 207,800 shares were granted in 2005 and were market condition awards which provided that employees may receive an aggregate of up to 100% of a share of common stock payable in common stock plus up to 100% of the fair market value of a share of common stock payable in cash. As a result of the Company’s ranking on the vesting date, 100% of the shares were paid in common stock and an additional 67% of the fair market value of each share of common stock, or $7.9 million, was paid in cash during the second quarter of 2008. Another 30,790 shares vested during 2008 and represent one-third of the three-year graded vesting schedule performance share awards granted in 2007 with a grant date per share value of $35.22. These awards met the performance criteria that the Company had positive operating income for the 2007 year. The remaining 11,400 shares vested as a result of the death of an employee of the Company.

During 2010, 2009 and 2008, 40,180, 120,090 and 37,000 performance shares, respectively, were forfeited.

Total unamortized compensation cost related to the equity component of performance shares at December 31, 2010 was $11.5 million and will be recognized over the next 1.9 years, computed by using the weighted-average of the time in 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, 2010, 2009 and 2008 was $12.4 million, $15.6 million and $17.5 million, respectively.

Deferred Performance Shares

As of December 31, 2010, 174,318 shares of the Company’s common stock representing vested performance share awards were deferred into the Rabbi Trust Deferred Compensation Plan. A total of 51,482 shares were sold out of the plan in 2010. During 2010, an increase to the rabbi trust deferred compensation liability of $2.5 million was recognized, representing the increase in the investment excluding the Company’s common stock, offset by the decrease in the closing price of the Company’s common stock from December 31, 2009 to December 31, 2010 and the reduction in the liability due to shares that were sold out of the rabbi trust. This increase in stock-based compensation expense was included in General and Administrative expense in the Consolidated Statement of Operations.

Supplemental Employee Incentive Plans

On January 16, 2008, the Company’s Board of Directors adopted a Supplemental Employee Incentive Plan. The plan was 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.

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The bonus payout was triggered if, for any 20 trading days (which need not be consecutive) that fell within a period of 60 consecutive trading days occurring on or before November 1, 2011, the closing price per share of the Company’s common stock equaled or exceeded the price goal of $60 per share. In such event, the 20th trading day on which such price condition was attained is the “Final Trigger Date.” Under the plan, each eligible employee would receive a minimum distribution of 50% of his or her base salary as of the Final Trigger Date, as adjusted for persons hired after December 31, 2007 to reflect calendar quarters of service, reduced by any interim distribution previously paid to such employee upon the achievement of the interim price goal discussed below. The Committee was authorized, in its discretion, to allocate to eligible employees additional distributions, subject to limitations of the plan.

The plan also provided that an interim distribution would be paid to eligible employees upon achieving the interim price goal of $50 per share prior to December 31, 2009. Interim distributions were determined as described above except that interim distributions were based on 10%, rather than 50%, of salary.

On the January 16, 2008 adoption date of the plan, the Company’s closing stock price was $40.71. On April 8, 2008 and subsequently on June 2, 2008, the Company achieved the interim and final target goals and total distributions of $15.7 million were paid in 2009. No further distributions will be made under this plan.

On July 24, 2008, the Company’s Board of Directors adopted a second Supplemental Employee Incentive Plan (“Plan II”). Plan II is also 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.

Plan II provides for a final payout if, for any 20 trading days (which need not be consecutive) that fall within a period of 60 consecutive trading days ending on or before June 20, 2012, the closing price per share of the Company’s common stock equals or exceeds the price goal of $105 per share. In such event, the 20th trading day on which such price condition is attained is the “Final Trigger Date.” The price goal is subject to adjustment by the Compensation Committee to reflect any stock splits, stock dividends or extraordinary cash distributions to stockholders. Under Plan II, each eligible employee may receive (upon approval by the Compensation Committee) a distribution of 50% of his or her base salary as of the Final Trigger Date (or 30% of base salary if the Company paid interim distributions upon the achievement of the interim price goal discussed below).

Plan II provides that a distribution of 20% of an eligible employee’s base salary as of the Interim Trigger Date will be made (upon approval by the Compensation Committee) upon achieving the interim price goal of $85 per share on or before June 30, 2010. The Company did not meet this interim trigger and therefore no distribution was made as of the Interim Trigger Date.

Payments under the final distribution will occur as follows:

•

25% of the total distribution paid on the 15 ^th business day following the final trigger date; and

•

75% of the total distribution paid based on the following deferred payment dates in the table below:


Period During which the Trigger Date Occurs		Deferred Payment Date
July 1, 2008 to June 30, 2009		The business day on or next following the 18 month anniversary of the applicable Trigger Date
July 1, 2009 to June 30, 2010		The business day on or next following the 12 month anniversary of the applicable Trigger Date
July 1, 2010 to December 31, 2010		The business day on or next following the 6 month anniversary of the applicable Trigger Date
January 1, 2011 to June 30, 2012		No deferral; entire payment is made on the 15 ^th business day following the applicable Trigger Date

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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 Plan II). Payments are subject to certain other restrictions contained in Plan II.

These awards under both plans discussed above have been accounted for as liability awards under ASC 718. The Company recognized a benefit of $0.9 million for 2010 and expense of $1.2 million for 2009, which is included in General and Administrative Expense in the Consolidated Statement of Operations.

13. Derivative Instruments and Hedging Activities

The Company periodically enters into commodity derivative instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. The Company’s credit agreement restricts the ability of the Company to enter into commodity hedges other than to hedge or mitigate risks to which the Company has actual or projected exposure or as permitted under the Company’s risk management policies and not subjecting the Company to material speculative risks. All of the Company’s derivatives are used for risk management purposes and are not held for trading purposes. As of December 31, 2010, the Company had 11 derivative contracts open: four natural gas price swap arrangements, six natural gas basis swaps arrangements and one crude oil collar arrangement. During 2010, the Company entered into six new derivative contracts covering anticipated crude oil production for 2010 and natural gas and crude oil production for 2011.

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


Commodity and Derivative Type	Weighted-Average Contract Price	Volume		Contract Period
Derivatives Designated as Hedging Instruments
Natural Gas Swaps	$6.24 per Mcf		12,909 Mmcf	January - December 2011
Crude Oil Collars	$93.25 Ceiling / $80.00 Floor per Bbl		365 Mbbl	January - December 2011

Derivatives Not Designated as Hedging Instruments
Natural Gas Basis Swaps	$(0.27) per Mcf		16,123 Mmcf	January - December 2012

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, as appropriate, in the Consolidated Statement of Operations.

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

Effect of Derivative Instruments on the Consolidated Balance Sheet


		Fair Value Asset (Liability)
*(In thousands)*	Balance Sheet Location	December 31, 2010			December 31, 2009
Derivatives Designated as Hedging Instruments
Natural Gas Commodity Contracts	Derivative Contracts (current assets)	$	18,669		$	99,151
Crude Oil Commodity Contracts	Derivative Contracts (current assets)		—			15,535
Natural Gas Commodity Contracts	Accrued Liabilities		—			(425	)
Crude Oil Commodity Contracts	Derivative Contracts (current assets)		(1,743	)		—

			16,926			114,261
Derivatives Not Designated as Hedging Instruments
Natural Gas Commodity Contracts	Other Liabilities		(2,180	)		(1,954	)

		$	14,746		$	112,307

At December 31, 2010 and 2009, unrealized gains of $16.9 million ($10.5 million, net of tax) and $114.3 million ($71.9 million, net of tax), respectively, were recorded in Accumulated Other Comprehensive Income. Based upon estimates at December 31, 2010, the Company expects to reclassify $10.5 million in after-tax income associated with its commodity hedges from Accumulated Other Comprehensive Income to the Consolidated Statement of Operations over the next 12 months.

Effect of Derivative Instruments on the Consolidated Statement of Operations


Derivatives Designated as Hedging Instruments (In thousands)	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion)							Location of Gain (Loss) Reclassified from Accumulated OCI into Income (In thousands)	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)
	Twelve Months Ended December 31,								Twelve Months Ended December 31,
	2010		2009			2008			2010		2009		2008
Natural Gas Commodity
Contracts	$	74,903	$	161,330		$	314,738	Natural Gas Revenues	$	154,960	$	371,915	$	17,972
Crude Oil Contracts		752		(7,244	)		46,213	Crude Oil and Condensate Revenues		18,030		23,112		(4,951	)

	$	75,655	$	154,086		$	360,951		$	172,990	$	395,027	$	13,021

For the years ended December 31, 2010, 2009 and 2008, respectively, there was no ineffectiveness recorded in our Consolidated Statement of Operations related to our derivative instruments.


Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss) Recognized in Income on Derivative	Twelve Months Ended December 31,
(In thousands)		2010			2009			2008
Natural Gas Commodity Contracts	Natural Gas Revenues	$	(226	)	$	(1,954	)	$	—

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Additional Disclosures about Derivative Instruments and Hedging Activities

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

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

14. Fair Value Measurements

Effective January 1, 2009, the Company applied all of the provisions of ASC 820 and there was not a material impact on the Company’s financial statements except for the Company’s impairment of oil and gas properties. The Company previously adopted the guidance as it relates to financial assets and liabilities that are measured at fair value on a recurring basis effective January 1, 2008. In the future, areas that could cause an impact would primarily be limited to asset impairments, including long-lived assets, asset retirement obligations and assets acquired and liabilities assumed in a business combination, if any.

As defined in ASC 820, 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 transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability.

The valuation techniques that can be used under ASC 820 are the market approach, income approach or cost approach. The market approach uses prices and other information for market transactions involving identical or comparable assets or liabilities, such as matrix pricing. The income approach uses valuation techniques to convert future amounts to a single discounted present value amount based on current market conditions about those future amounts, such as present value techniques, option pricing models (i.e. Black-Scholes model) and binomial models (i.e. Monte-Carlo model). The cost approach is based on current replacement cost to replace an asset.

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. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. ASC 820 establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements, and accordingly, Level 1 measurements should be used whenever possible.

The three levels of the fair value hierarchy as defined by ASC 820 are as follows:

•

Level 1: Valuations utilizing quoted, unadjusted prices for identical assets or liabilities in active markets that the Company has the ability to access. This is the most reliable evidence of fair value and does not require a significant degree of judgment. Examples include exchange-traded derivatives and listed equities that are actively traded.

•

Level 2: Valuations utilizing quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially

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the full term of the asset or liability. Financial instruments that are valued using models or other valuation methodologies are included. Models used should primarily be industry-standard models that consider various assumptions and economic measures, such as interest rates, yield curves, time value, volatilities, contract terms, current market prices, credit risk or other market-corroborated inputs. Examples include most over-the-counter derivatives (non-exchange traded), physical commodities, most structured notes and municipal and corporate bonds.

•

Level 3: Valuations utilizing significant, unobservable inputs. This provides the least objective evidence of fair value and requires a significant degree of judgment. Inputs may be used with internally developed methodologies and should reflect an entity’s assumptions using the best information available about the assumptions that market participants would use in pricing an asset or liability. Examples include certain corporate loans, real-estate and private equity investments and long-dated or complex over-the-counter derivatives.

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 ASC 820, the lowest level that contains significant inputs used in valuation should be chosen. In accordance with ASC 820, the Company has classified its assets and liabilities into these levels depending upon the data relied on to determine the fair values.

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as asset retirement obligations and impairments of long-lived assets, at fair value on a nonrecurring basis. During the year ended December 31, 2010, the Company recorded impairment charges related to certain 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, 2010 and 2009 and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures were not provided.

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 as of December 31, 2010 and 2009:


(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, 2010
Assets
Rabbi Trust Deferred Compensation Plan	$	15,788	$	—	$	—		$	15,788
Derivative Contracts		—		—		16,926			16,926

Total Assets	$	15,788	$	—	$	16,926		$	32,714

Liabilities
Rabbi Trust Deferred Compensation Plan	$	21,600	$	—	$	—		$	21,600
Derivative Contracts		—		—		(2,180	)		(2,180	)

Total Liabilities	$	21,600	$	—	$	(2,180	)	$	19,420

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(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, 2009
Assets
Rabbi Trust Deferred Compensation Plan	$	10,031	$	—	$	—	$	10,031
Derivative Contracts		—		—		114,686		114,686

Total Assets	$	10,031	$	—	$	114,686	$	124,717

Liabilities
Rabbi Trust Deferred Compensation Plan	$	19,087	$	—	$	—	$	19,087
Derivative Contracts		—		—		2,379		2,379

Total Liabilities	$	19,087	$	—	$	2,379	$	21,466

The Company’s investments associated with its Rabbi Trust Deferred Compensation Plan consist of mutual funds and deferred shares of the Company’s common stock that are publicly traded and for which market prices are readily available. The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using relevant NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. 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. The resulting reduction to the net receivable derivative contract position was $0.1 million. In times where the Company has net derivative contract liabilities, the nonperformance risk of the Company is evaluated using a market credit spread provided by the Company’s bank.

The following table sets forth a reconciliation of changes for the years ended December 31, 2010 and 2009 in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:


	December 31,
(In thousands)	2010			2009			2008
Balance at beginning of period	$	112,307		$	355,202		$	7,272
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings ⁽¹⁾		172,764			393,073			13,021
Included in Other Comprehensive Income		(97,335	)		(240,941	)		347,930
Purchases, Issuances and Settlements		(172,990	)		(395,027	)		(13,021	)
Transfers In and/or Out of Level 3		—			—			—

Balance at end of period	$	14,746		$	112,307		$	355,202

⁽¹⁾	A loss of $0.2 million and $2.0 million for the years ended December 31, 2010 and 2009, respectively was unrealized and included in Natural Gas Revenues in the Statement of Operations. All gains included in earnings for the year ended December 31, 2008 were realized.

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

Fair Value of Other Financial Instruments

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

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

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

December 31, 2010

December 31, 2009

(In thousands)

Carrying
Amount

Estimated
Fair Value

Carrying
Amount

Estimated
Fair Value

Long-Term Debt

975,000

1,100,830

805,000

863,559

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 for the years ended December 31, 2010, 2009 and 2008:


	December 31,
	2010		2009		2008
Weighted-Average Shares—Basic		103,911,431		103,615,971		100,736,562
Dilution Effect of Stock Options, Stock Appreciation Rights and Stock Awards at End of Period		1,283,354		1,066,776		989,936

Weighted-Average Shares—Diluted		105,194,785		104,682,747		101,726,498

Weighted-Average Stock Awards and Shares Excluded from Diluted Earnings per Share due to the Anti-Dilutive Effect		283,566		260,818		258,074

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16. Accumulated Other Comprehensive Income / (Loss)

Changes in the components of accumulated other comprehensive income / (loss), net of taxes, for the years ended December 31, 2010, 2009 and 2008 were as follows:


	Net Gains / (Losses) on Cash Flow Hedges			Defined Benefit Pension and Postretirement Plans			Foreign Currency Translation Adjustment			Total
Balance at December 31, 2007	$	4,553		$	(14,027	)	$	8,580		$	(894	)

Net change in unrealized gain on cash flow hedges, net of taxes of $(129,415)		218,515			—			—			218,515
Net change in defined benefit pension and postretirement plans, net of taxes of $9,235		—			(15,581	)		—			(15,581	)
Change in foreign currency translation adjustment, net of taxes of $9,292		—			—			(15,614	)		(15,614	)

Balance at December 31, 2008	$	223,068		$	(29,608	)	$	(7,034	)	$	186,426

Net change in unrealized gain on cash flow hedges, net of taxes of $89,745		(151,196	)		—			—			(151,196	)
Net change in defined benefit pension and postretirement plans, net of taxes of $(162)		—			259			—			259
Change in foreign currency translation adjustment, net of taxes of $(4,116)		—			—			6,947			6,947

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	)

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CABOT OIL & GAS CORPORATION

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Oil and Gas Reserves

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

Estimates of total proved reserves at December 31, 2010, 2009 and 2008 were based on studies performed by the Company’s petroleum engineering staff. The 2010 and 2009 estimates were computed using the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year, as prescribed under the revised rules codified in ASC 932, “Extractive Activities—Oil and Gas”. The 2008 estimates were computed based on year end prices for oil and natural gas. 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, 2010, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

As of December 31, 2009, the Company adopted the guidance in ASC 932 related to oil and gas reserve estimation and disclosures in conjunction with the year-end reserve reporting as a change in accounting principle that is inseparable from a change in accounting estimate. The impact of the adoption of this guidance on the Company’s financial statements was not practicable to estimate due to the challenges associated with computing a cumulative effect of adoption by preparing reserve reports under both the old and new guidance.

- 105 -

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 2010 and 2009 and, to a lesser extent, Canada in 2008.


	Natural Gas *(Mmcf)*			Oil & Liquids *(Mbbl)*			Total *(Mmcfe) ⁽¹⁾*
December 31, 2007 ⁽⁵⁾		1,559,953			9,328			1,615,919

Revision of Prior Estimates ⁽²⁾		(47,745	)		(1,593	)		(57,302	)
Extensions, Discoveries and Other Additions		297,089			1,134			303,895
Production.		(90,425	)		(794	)		(95,191	)
Purchases of Reserves in Place		167,262			1,268			174,872
Sales of Reserves in Place		(141	)		(2	)		(156	)

December 31, 2008 ⁽⁵⁾		1,885,993			9,341			1,942,037

Revision of Prior Estimates ⁽³⁾		(193,767	)		(1,062	)		(200,143	)
Extensions, Discoveries and Other Additions		459,612			544			462,880
Production		(97,914	)		(844	)		(102,976	)
Purchases of Reserves in Place		9			—			9
Sales of Reserves in Place		(40,771	)		(196	)		(41,949	)

December 31, 2009		2,013,162			7,783			2,059,858

Revision of Prior Estimates ⁽⁴⁾		139,016			(379	)		136,742
Extensions, Discoveries and Other Additions		632,980			2,944			650,644
Production		(125,474	)		(858	)		(130,622	)
Purchases of Reserves in Place		593			4			617
Sales of Reserves in Place		(16,119	)		(3	)		(16,137	)

December 31, 2010		2,644,158			9,491			2,701,102


Proved Developed Reserves
December 31, 2007		1,133,937			7,026			1,176,091
December 31, 2008		1,308,155			6,728			1,348,521
December 31, 2009		1,288,169			6,082			1,324,663
December 31, 2010		1,681,451			7,129			1,724,225

Proved Undeveloped Reserves
December 31, 2007		426,016			2,302			439,828
December 31, 2008		577,838			2,613			593,516
December 31, 2009		724,993			1,701			735,199
December 31, 2010		962,707			2,362			976,877

⁽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 majority of the revisions were the result of the decrease in the natural gas price.

⁽³⁾

⁽⁴⁾

⁽⁵⁾	Prior to 2009, reserve estimates were based on year end prices.

- 106 -

Capitalized Costs Relating to Oil and Gas Producing Activities

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


	December 31,
(In thousands)	2010		2009		2008
Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities	$	5,598,842	$	4,905,424	$	4,465,630
Aggregate Accumulated Depreciation, Depletion and Amortization		1,840,091		1,550,837		1,331,243

Net Capitalized Costs		3,758,751		3,354,587		3,134,387

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

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


	Year Ended December 31,
(In thousands)	2010		2009		2008
Property Acquisition Costs, Proved	$	801	$	394	$	605,860
Property Acquisition Costs, Unproved		130,675		145,681		152,666
Exploration Costs		66,368		68,196		82,972
Development Costs		630,511		379,140		600,269

Total Costs	$	828,355	$	593,411	$	1,441,767

Results of Operations for Producing Activities

The results of operations for the Company’s oil and gas producing activities were as follows:


	Year Ended December 31,
(In thousands)	2010		2009		2008
Operating Revenues	$	775,974	$	800,464	$	829,208
Costs and Expenses
Production		120,322		121,087		140,763
Exploration		42,725		50,784		31,200
Depreciation, Depletion and Amortization		364,452		265,402		259,399

Total Costs and Expenses		527,499		437,273		431,362

Income Before Income Taxes		248,475		363,191		397,846
Provision for Income Taxes		94,293		133,312		146,361

Results of Operations	$	154,182	$	229,879	$	251,485

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

The following information has been developed utilizing the guidance in ASC 932 and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

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

•

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

•

Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.

•

Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.

•

Future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows for 2010 and 2009 were estimated by using the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year, as prescribed under the revised rules codified in ASC 932 that the Company adopted on January 1, 2010, and by applying year end oil and gas prices to the estimated future production of year end proved reserves for 2008.

The average prices (adjusted for basis and quality differentials) related to proved reserves at December 31, 2010, 2009 and 2008 for natural gas ($ per Mcf) were $4.33, $3.84 and $5.66, respectively, and for oil ($ per Bbl) were $74.25, $55.41 and $40.15, respectively. Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations. ASC 932 requires the use of a 10% discount rate.

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

Standardized Measure is as follows:


	Year Ended December 31,
(In thousands)	2010			2009			2008
Future Cash Inflows	$	12,147,617		$	8,170,009		$	11,050,932
Future Production Costs		(2,377,402	)		(2,353,974	)		(3,018,154	)
Future Development Costs		(1,670,796	)		(1,234,203	)		(1,354,780	)
Future Income Tax Expenses		(2,357,935	)		(1,089,282	)		(1,891,928	)

Future Net Cash Flows		5,741,484			3,492,550			4,786,070
10% Annual Discount for Estimated Timing of Cash Flows		(3,006,975	)		(1,860,815	)		(2,726,115	)

Standardized Measure of Discounted Future Net Cash Flows	$	2,734,509		$	1,631,735		$	2,059,955

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

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


	Year Ended December 31,
(In thousands)	2010			2009			2008
Beginning of Year	$	1,631,735		$	2,059,955		$	2,170,651
Discoveries and Extensions, Net of Related Future Costs		780,917			381,691			341,156
Net Changes in Prices and Production Costs		991,942			(861,939	)		(692,803	)
Accretion of Discount		164,189			236,520			300,766
Revisions of Previous Quantity Estimates		164,851			(159,531	)		(69,788	)
Timing and Other		(105,331	)		(104,117	)		(157,194	)
Development Costs Incurred		115,560			109,384			157,194
Sales and Transfers, Net of Production Costs		(481,556	)		(286,594	)		(688,657	)
Net Purchases / (Sales) of Reserves in Place		(16,124	)		(38,730	)		166,873
Net Change in Income Taxes		(511,674	)		295,096			531,757

End of Year	$	2,734,509		$	1,631,735		$	2,059,955

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CABOT OIL & GAS CORPORATION

SELECTED DATA (UNAUDITED)

QUARTERLY FINANCIAL INFORMATION


(In thousands , except per share amounts )	First		Second		Third		Fourth		Total
2010
Operating Revenues	$	212,556	$	195,474	$	219,130	$	216,875	$	844,035
Impairment of Oil & Gas Properties and Other Assets ⁽¹⁾		—		—		35,789		5,114		40,903
Operating Income ⁽²⁾		60,589		52,068		22,274		131,508		266,439
Net Income ⁽²⁾		28,696		21,682		3,899		49,109		103,386
Basic Earnings per Share		0.28		0.21		0.04		0.47		0.99
Diluted Earnings per Share		0.27		0.21		0.04		0.47		0.98

2009
Operating Revenues	$	233,939	$	204,824	$	207,021	$	233,492	$	879,276
Impairment of Oil & Gas Properties and Other Assets ⁽¹⁾		—		—		—		17,622		17,622
Operating Income ⁽³⁾		89,897		54,239		74,723		63,410		282,269
Net Income ⁽³⁾		47,580		25,502		38,897		36,364		148,343
Basic Earnings per Share		0.46		0.25		0.38		0.34		1.43
Diluted Earnings per Share		0.46		0.24		0.37		0.35		1.42

⁽¹⁾	For discussion of impairment of oil and gas properties, refer to Note 2 of the Notes to the Consolidated Financial Statements.

⁽²⁾

Operating Income and Net Income in the second and fourth quarters of 2010 contain a $10.3 million gain on the disposition of the Woodford shale prospect and an impairment loss of $5.8 million associated with the third quarter sale of certain oil and gas properties in Colorado in the second quarter of 2010 and a gain of $11.4 million related to the sale of certain oil and gas properties in the Texas Panhandle as well as a gain of $49.3 million associated with the sale of the Pennsylvania gathering infrastructure and a $40.7 million gain from the sale of the Company’s investment in Tourmaline in the fourth quarter of 2010, respectively.

⁽³⁾	Operating Income and Net Income in the first and second quarters of 2009 contain a $12.7 million gain on the disposition of Thornwood properties and a $16.0 million loss on the sale of Canadian properties, respectively.

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ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

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

As of December 31, 2010, 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 has materially affected, or is reasonably likely to materially effect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting

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

Cabot Oil & Gas Corporation’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. 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 our assessment we have concluded that, as of December 31, 2010, 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, 2010, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

ITEM 9B.

OTHER INFORMATION

None.

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PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting. In addition, the information set forth under the caption “Business-Other Business Matters-Corporate Governance Matters” in Item 1 regarding our Code of Business Conduct is incorporated by reference in response to this Item.

ITEM 11.

EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is incorporated by reference to the Company’s definitive Proxy Statement in connection with the 2011 annual stockholders’ meeting.

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

INDEX

1.	Consolidated Financial Statements

See Index on page 54.

2.	Financial Statement Schedules

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

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3.	Exhibits

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


Exhibit Number		Description
***2.1		Purchase and Sale Agreement dated June 3, 2008 by and among Enduring Resources, LLC, Mustang Drilling, Inc., Minden Gathering Services, LLC and Cabot Oil & Gas Corporation (Form 10-Q for the quarter ended June 30, 2008).

3.1		Restated Certificate of Incorporation of the Company (Form 8-K for January 21, 2010).

3.2		Amended and Restated Bylaws of the Company amended January 14, 2010 (Form 8-K for January 14, 2010).

4.1		Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553).

4.2		Note Purchase Agreement dated as of July 26, 2001 among Cabot Oil & Gas Corporation and the Purchasers listed therein (Form 8-K for August 30, 2001).
		(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).
		(b) Amendment No. 2 to Note Purchase Agreement, dated as of September 28, 2010 (Form 10-Q for the quarter ended September 30, 2010).

4.3		Note Purchase Agreement dated as of July 16, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 8-K for July 16, 2008).
		(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).

4.4		Note Purchase Agreement dated as of December 1, 2008 among Cabot Oil & Gas Corporation and the Purchasers named therein (Form 10-K for 2008).
		(a) Amendment No. 1 to Note Purchase Agreement, dated as of June 30, 2010 (Form 10-Q for the quarter ended June 30, 2010).

4.5		Note Purchase Agreement dated as of December 30, 2010 among Cabot Oil & Gas Corporation and the Purchasers named therein.

4.6		Credit Agreement, dated as of September 22, 2010, among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Banc of America Securities LLC, as Syndication Agent, Bank of Montreal, as Documentation Agent, and the Lenders party thereto (Form 10-Q for the quarter ended September 30, 2010).

*10.1		Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 2008).
		(a) Form of Change in Control Agreement between the Company and Certain Officers (Confirmation that Certain Benefits no Longer Apply).

*10.2		Form of Supplemental Executive Retirement Agreement (Form 10-K for 2008).
		(a) Agreement Concerning SERP.

*10.3		1990 Non-employee Director Stock Option Plan of the Company (Form S-8) (Registration No. 33-35478).
		(a) First Amendment to 1990 Non-employee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8) (Registration No. 33-35478).
		(b) Second Amendment to 1990 Non-employee Director Stock Option Plan (Form 10-K for 1995).

- 113 -


Exhibit Number		Description
*10.4		Second Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form 10-K for 2001).

*10.5		Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001).

*10.6		Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997).

*10.7		Deferred Compensation Plan of the Company, as Amended and Restated, Effective January 1, 2009 (Form 10-K for 2008).
		(a) First amendment to the Deferred Compensation Plan of the Company, effective October 1, 2010.
		(b) Second amendment to the Deferred Compensation Plan of the Company, effective October 26, 2010.

10.8		Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001).

10.9		Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998).

*10.10		Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001).
		(a) Amendment to Employment Agreement between the Company and Dan O. Dinges, effective December 31, 2008 (Form 10-K for 2008).

*10.11		2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004).
		(a) First Amendment to the 2004 Incentive Plan effective February 23, 2007 (Form 10-Q for the quarter ended March 31, 2007).
		(b) Second Amendment to the 2004 Incentive Plan Amendment, effective as of January 1, 2009 (Form 10-K for 2008).

*10.12		2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004).

*10.13		2004 Annual Target Cash Incentive Plan Measurement Criteria for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).

*10.14		Form of Restricted Stock Awards Terms and Conditions for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).

*10.15		2005 Form of Non-Employee Director Restricted Stock Unit Award Agreement (Form 8-K for May 24, 2005).

*10.16		Savings Investment Plan of the Company, as amended and restated effective January 1, 2001 (Form 10-K for 2005).
		(a) First Amendment to the Savings Investment Plan effective January 1, 2002 (Form 10-K for 2005).
		(b) Second Amendment to the Savings Investment Plan effective January 1, 2003 (Form 10-K for 2005).
		(c) Third Amendment to the Savings Investment Plan effective January 1, 2005 (Form 10-K for 2005).

*10.17		Forms of Award Agreements for Executive Officers under 2004 Incentive Plan (Form 10-K for 2006).
		(a) Form of Restricted Stock Award Agreement (Form 10-K for 2006).
		(b) Form of Stock Appreciation Rights Award Agreement (Form 10-K for 2006).
		(c) Form of Performance Share Award Agreement (Form 10-K for 2006).

- 114 -


Exhibit Number		Description
10.18		Cabot Oil & Gas Corporation Mineral, Royalty and Overriding Royalty Interest Plan (Registration Statement No. 333-135365).
		(a) Form of Conveyance of Mineral and/or Royalty Interest (Registration Statement No. 333-135365).
		(b) Form of Conveyance of Overriding Royalty Interest (Registration Statement No. 333-135365).

10.19		Purchase and Sale Agreement dated August 25, 2006 between Cabot Oil & Gas Corporation, a Delaware corporation, Cody Energy LLC, a Colorado limited liability company, and Phoenix Exploration Company LP, a Delaware limited partnership (Form 8-K for September 29, 2006).

*10.20		Form of Amendment of Employee Award Agreements (Form 8-K for December 19, 2006).

*10.21		Savings Investment Plan of the Company, as amended and restated effective January 1, 2006 (Form 10-K for 2006).
		(a) First Amendment to the Savings Investment Plan of the Company effective January 1, 2006 (Form 10-K for 2007).
		(b) Second Amendment to the Savings Investment Plan of the Company effective April 23, 2008 (Form 10-Q for the quarter ended March 31, 2008).
		(c) Third Amendment to the Savings Investment Plan of the Company effective July 1, 2008 (Form 10-K for 2008).
		(d) Fourth Amendment to the Savings Investment Plan of the Company effective January 1, 2008 (Form 10-K for 2008).

*10.22		Cabot Oil & Gas Corporation Pension Plan, as amended and restated effective September 30, 2010.

*10.23		Savings Investment Plan of the Company, as amended and restated effective January 1, 2009 (Form 10-K for 2009).
		(a) First Amendment to the Savings Investment Plan of the Company effective January 1, 2009.

21.1		Subsidiaries of Cabot Oil & Gas Corporation.

23.1		Consent of PricewaterhouseCoopers LLP.

23.2		Consent of Miller and Lents, Ltd.

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.

Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

***	Certain schedules to the exhibit are omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish to the SEC, upon request, copies of any such schedules.

- 115 -

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 2011.


CABOT OIL & GAS CORPORATION

By:		/ S / D AN O. D INGES
		Dan O. Dinges
		Chairman, President and Chief Executive Officer

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


Signature	Title	Date

/ S / D AN O. D INGES Dan O. Dinges	Chairman, President and Chief Executive Officer (Principal Executive Officer)	February 28, 2011

/ S / S COTT C. S CHROEDER Scott C. Schroeder	Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)	February 28, 2011

/ S / T ODD M. R OEMER Todd M. Roemer	Controller (Principal Accounting Officer)	February 28, 2011

/ S / R HYS J. B EST Rhys J. Best	Director	February 28, 2011

/ S / D AVID M. C ARMICHAEL David M. Carmichael	Director	February 28, 2011

/ S / J AMES R. G IBBS James R. Gibbs	Director	February 28, 2011

/ S / R OBERT L. K EISER Robert L. Keiser	Director	February 28, 2011

/ S / R OBERT K ELLEY Robert Kelley	Director	February 28, 2011

/ S / P. D EXTER P EACOCK P. Dexter Peacock	Director	February 28, 2011

/ S / W ILLIAM P. V ITITOE William P. Vititoe	Director	February 28, 2011

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Exhibit 4.5

EXECUTION VERSION

CABOT OIL & GAS CORPORATION

$88,000,000 5.42% Series H Senior Notes due January 15, 2021

$25,000,000 5.59% Series I Senior Notes due January 15, 2023

$62,000,000 5.80% Series J Senior Notes due January 15, 2026

NOTE PURCHASE AGREEMENT

Dated December 30, 2010

TABLE OF CONTENTS


			Page
1.	AUTHORIZATION OF NOTES			1

2.	SALE AND PURCHASE OF NOTES			1

3.	CLOSING			2

4.	CONDITIONS TO CLOSING			2

	4.1.	Representations and Warranties		2
	4.2.	Performance; No Default		2
	4.3.	Compliance Certificates		2
	4.4.	Opinions of Counsel		3
	4.5.	Purchase Permitted By Applicable Law, Etc.		3
	4.6.	Sale of Other Notes		3
	4.7.	Payment of Special Counsel Fees		3
	4.8.	Private Placement Number		4
	4.9.	Changes in Corporate Structure		4
	4.10.	Funding Instructions		4
	4.11.	Proceedings and Documents		4

5.	REPRESENTATIONS AND WARRANTIES OF THE COMPANY			4

	5.1.	Organization; Power and Authority		4
	5.2.	Authorization, Etc.		5
	5.3.	Disclosure		5
	5.4.	Organization and Ownership of Shares of Subsidiaries; Affiliates		5
	5.5.	Financial Statements; Material Liabilities		6
	5.6.	Compliance with Laws, Other Instruments, Etc.		6
	5.7.	Governmental Authorizations, Etc.		6
	5.8.	Litigation; Observance of Agreements, Statutes and Orders		7
	5.9.	Taxes		7
	5.10.	Title to Property; Leases		7
	5.11.	Licenses, Permits, Etc.		8
	5.12.	Compliance with ERISA		8
	5.13.	Private Offering by the Company		9
	5.14.	Use of Proceeds; Margin Regulations		9
	5.15.	Existing Indebtedness; Future Liens		9
	5.16.	Foreign Assets Control Regulations, Etc.		10
	5.17.	Status under Certain Statutes		11
	5.18.	Environmental Matters		11
	5.19.	Ranking of Obligations		11

6.	REPRESENTATIONS OF THE PURCHASERS			11

	6.1.	Purchase for Investment		11
	6.2.	Source of Funds		12

TABLE OF CONTENTS

(continued)


			Page
7.	INFORMATION AS TO COMPANY			13

	7.1.	Financial and Business Information		13
	7.2.	Officer’s Certificate		16
	7.3.	Visitation		17

8.	PAYMENT AND PREPAYMENT OF THE NOTES			17

	8.1.	Maturity		17
	8.2.	Optional Prepayments with Make-Whole Amount		17
	8.3.	Prepayment of Notes Upon Change of Control		18
	8.4.	Prepayment in Connection with a Disposition		19
	8.5.	Allocation of Partial Prepayments		20
	8.6.	Maturity; Surrender, Etc.		20
	8.7.	Purchase of Notes		20
	8.8.	Make-Whole Amount		20

9.	AFFIRMATIVE COVENANTS			22

	9.1.	Compliance with Law		22
	9.2.	Insurance		22
	9.3.	Maintenance of Properties		22
	9.4.	Payment of Taxes and Claims		23
	9.5.	Corporate Existence, Etc.		23
	9.6.	Books and Records		23
	9.7.	Ranking of Obligations		24
	9.8.	Subsidiary Guaranty; Release of Guaranties		24

10.	NEGATIVE COVENANTS			25

	10.1.	Transactions with Affiliates		25
	10.2.	Merger, Consolidation, Etc.		25
	10.3.	Line of Business		26
	10.4.	Terrorism Sanctions Regulations		26
	10.5.	Liens		26
	10.6.	Sale of Assets		27
	10.7.	Priority Debt		28
	10.8.	Asset Coverage Ratio		29
	10.9.	Annual Coverage Ratio		29

11.	EVENTS OF DEFAULT			30

12.	REMEDIES ON DEFAULT, ETC.			32

	12.1.	Acceleration		32
	12.2.	Other Remedies		32
	12.3.	Rescission		33
	12.4.	No Waivers or Election of Remedies, Expenses, Etc.		33

TABLE OF CONTENTS

(continued)


			Page

13.	REGISTRATION; EXCHANGE; SUBSTITUTION OF NOTES			33

	13.1.	Registration of Notes		33
	13.2.	Transfer and Exchange of Notes		34
	13.3.	Replacement of Notes		34

14.	PAYMENTS ON NOTES			34

	14.1.	Place of Payment		34
	14.2.	Home Office Payment		35

15.	EXPENSES, ETC.			35

	15.1.	Transaction Expenses		35
	15.2.	Survival		36

16.	SURVIVAL OF REPRESENTATIONS AND WARRANTIES; ENTIRE AGREEMENT			36

17.	AMENDMENT AND WAIVER			36

	17.1.	Requirements		36
	17.2.	Solicitation of Holders of Notes		36
	17.3.	Binding Effect, etc.		37
	17.4.	Notes Held by Company, etc.		37

18.	NOTICES			38

19.	REPRODUCTION OF DOCUMENTS			38

20.	CONFIDENTIAL INFORMATION			39

21.	SUBSTITUTION OF PURCHASER			39

22.	MISCELLANEOUS			40

	22.1.	Successors and Assigns		40
	22.2.	Payments Due on Non-Business Days		40
	22.3.	Accounting Terms		40
	22.4.	Severability		40
	22.5.	Construction, etc.		41
	22.6.	Counterparts		41
	22.7.	Governing Law		41
	22.8.	Jurisdiction and Process; Waiver of Jury Trial		41

iii


Schedule A	—	Information Relating to Purchasers

Schedule B	—	Defined Terms

Schedule 5.3	—	Disclosure Materials

Schedule 5.4	—	Subsidiaries of the Company and Ownership of Subsidiary Stock

Schedule 5.5	—	Financial Statements

Schedule 5.15	—	Existing Indebtedness

Schedule 10.5	—	Liens

Exhibit 1(a)	—	Form of 5.42% Series H Senior Note due January 15, 2021

Exhibit 1(b)	—	Form of 5.59% Series I Senior Note due January 15, 2023

Exhibit 1(c)	—	Form of 5.80% Series J Senior Note due January 15, 2026

Exhibit 4.4(a)	—	Form of Opinion of Managing Counsel for the Company

Exhibit 4.4(b)	—	Form of Opinion of Special Counsel for the Company

Exhibit 4.4(c)	—	Form of Opinion of Special Counsel for the Purchasers

CABOT OIL & GAS CORPORATION

Three Memorial City Plaza

840 Gessner Road, Suite 1400

Houston, Texas 77024

$88,000,000 5.42% Series H Senior Notes due January 15, 2021

$25,000,000 5.59% Series I Senior Notes due January 15, 2023

$62,000,000 5.80% Series J Senior Notes due January 15, 2026

December 30, 2010

To Each of The Purchasers Listed in

Schedule A Hereto:

Ladies and Gentlemen:

CABOT OIL & GAS CORPORATION , a Delaware corporation (the “ Company ”), agrees with each of the purchasers whose names appear at the end hereof (each, a “ Purchaser ” and, collectively, the “ Purchasers ”) as follows:

1.	AUTHORIZATION OF NOTES.

The Company will authorize the issue and sale of (a) $88,000,000 aggregate principal amount of its 5.42% Series H Senior Notes due January 15, 2021 (the “ Series H Notes ”), (b) $25,000,000 aggregate principal amount of its 5.59% Series I Senior Notes due January 15, 2023 (the “ Series I Notes ”), and (c) and $62,000,000 aggregate principal amount of its 5.80% Series J Senior Notes due January 15, 2026 (the “ Series J Notes ” and together with the Series H Notes and Series I Notes collectively, the “ Notes ”, such term to include any such notes issued in substitution therefor pursuant to Section 13). The Series H Notes, Series I Notes and Series J Notes shall be substantially in the forms set out in Exhibit 1(a), Exhibit 1(b) and Exhibit 1(c), respectively. Certain capitalized and other terms used in this Agreement are defined in Schedule B; and references to a “Schedule” or an “Exhibit” are, unless otherwise specified, to a Schedule or an Exhibit attached to this Agreement.

2.	SALE AND PURCHASE OF NOTES.

Subject to the terms and conditions of this Agreement, the Company will issue and sell to each Purchaser and each Purchaser will purchase from the Company, at the Closing provided for in Section 3, Notes in the principal amount and in the Series specified opposite such Purchaser’s name in Schedule A at the purchase price of 100% of the principal amount thereof. The Purchasers’ obligations hereunder are several and not joint obligations and no Purchaser shall have any liability to any Person for the performance or non-performance of any obligation by any other Purchaser hereunder.

3.	CLOSING.

The sale and purchase of the Notes to be purchased by each Purchaser shall occur at the offices of Bingham McCutchen LLP, One State Street, Hartford, CT 06103, at 10:00 a.m., local time, at a closing (the “ Closing ”) on December 30, 2010 or on such other Business Day thereafter on or prior to January 10, 2011 as may be agreed upon by the Company and the Purchasers. At the Closing the Company will deliver to each Purchaser the Notes to be purchased by such Purchaser in the form of a single Note of each Series to be purchased by such Purchaser (or such greater number of Notes of each such Series in denominations of at least $500,000 as such Purchaser may request) dated the date of the Closing and registered in such Purchaser’s name (or in the name of its nominee), against delivery by such Purchaser to the Company or its order of immediately available funds in the amount of the purchase price therefor by wire transfer of immediately available funds for the account of the Company to account number 636462608 at JPMorgan Chase Bank, N.A., 1717 Mail Street, 3 ^rd Floor, Dallas, TX 75201, ABA number 021000021. If at the Closing the Company shall fail to tender such Notes to any Purchaser as provided above in this Section 3, or any of the conditions specified in Section 4 shall not have been fulfilled to such Purchaser’s satisfaction, such Purchaser shall, at its election, be relieved of all further obligations under this Agreement, without thereby waiving any rights such Purchaser may have by reason of such failure or such nonfulfillment.

4.	CONDITIONS TO CLOSING.

Each Purchaser’s obligation to purchase and pay for the Notes to be sold to such Purchaser at the Closing is subject to the fulfillment to such Purchaser’s satisfaction, prior to or at the Closing, of the following conditions:

4.1.

Representations and Warranties.

The representations and warranties of the Company in this Agreement shall be correct when made and at the time of the Closing.

4.2.

Performance; No Default.

The Company shall have performed and complied with all agreements and conditions contained in this Agreement required to be performed or complied with by it prior to or at the Closing and after giving effect to the issue and sale of the Notes (and the application of the proceeds thereof as contemplated by Section 5.14) no Default or Event of Default shall have occurred and be continuing. Neither the Company nor any Subsidiary shall have entered into any transaction since the date of the Memorandum that would have been prohibited by Sections 10.1, 10.5 or 10.7 had such Sections applied since such date.

4.3.

Compliance Certificates.

(a) Officer’s Certificate . The Company shall have delivered to such Purchaser an Officer’s Certificate, dated the date of the Closing, certifying that the conditions specified in Sections 4.1, 4.2 and 4.9 have been fulfilled.

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(b) Secretary’s Certificates . The Company shall have delivered to such Purchaser a certificate of its Secretary or Assistant Secretary, dated the date of Closing, certifying as to the resolutions attached thereto and other corporate proceedings relating to the authorization, execution and delivery of the Notes, this Agreement and the Subsidiary Guaranty, as applicable.

4.4.

Opinions of Counsel.

Such Purchaser shall have received opinions in form and substance satisfactory to such Purchaser, dated the date of the Closing (a) from Lisa A. Machesney, Managing Counsel for the Company, covering the matters set forth in Exhibit 4.4(a) and covering such other matters incident to the transactions contemplated hereby as such Purchaser or its counsel may reasonably request (and the Company hereby instructs its counsel to deliver such opinion to the Purchasers), (b) from Baker Botts LLP, counsel for the Company, covering the matters set forth in Exhibit 4.4(b) and covering such other matters incident to the transactions contemplated hereby as such Purchaser or its counsel may reasonably request (and the Company hereby instructs its counsel to deliver such opinion to the Purchasers) and (c) from Bingham McCutchen LLP, the Purchasers’ special counsel in connection with such transactions, substantially in the form set forth in Exhibit 4.4(c) and covering such other matters incident to such transactions as such Purchaser may reasonably request.

4.5.

Purchase Permitted By Applicable Law, Etc.

On the date of the Closing such Purchaser’s purchase of Notes shall (a) be permitted by the laws and regulations of each jurisdiction to which such Purchaser is subject, without recourse to provisions (such as section 1405(a)(8) of the New York Insurance Law) permitting limited investments by insurance companies without restriction as to the character of the particular investment, (b) not violate any applicable law or regulation (including, without limitation, Regulation T, U or X of the Board of Governors of the Federal Reserve System) and (c) not subject such Purchaser to any tax, penalty or liability under or pursuant to any applicable law or regulation, which law or regulation was not in effect on the date hereof. If requested by such Purchaser, such Purchaser shall have received an Officer’s Certificate certifying as to such matters of fact as such Purchaser may reasonably specify to enable such Purchaser to determine whether such purchase is so permitted.

4.6.

Sale of Other Notes.

Contemporaneously with the Closing the Company shall sell to each other Purchaser and each other Purchaser shall purchase the Notes to be purchased by it at the Closing as specified in Schedule A.

4.7.

Payment of Special Counsel Fees.

Without limiting the provisions of Section 15.1, the Company shall have paid on or before the Closing the fees, charges and disbursements of the Purchasers’ special counsel referred to in Section 4.4 to the extent reflected in a statement of such counsel rendered to the Company at least one Business Day prior to the Closing.

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4.8.

Private Placement Number.

A Private Placement Number issued by Standard & Poor’s CUSIP Service Bureau (in cooperation with the SVO) shall have been obtained for each Series of Notes.

4.9.

Changes in Corporate Structure.

The Company shall not have changed its jurisdiction of incorporation or organization, as applicable, or been a party to any merger or consolidation or succeeded to all or any substantial part of the liabilities of any other entity, at any time following the date of the most recent financial statements referred to in Schedule 5.5.

4.10.

Funding Instructions.

At least three Business Days prior to the date of the Closing, each Purchaser shall have received written instructions signed by a Responsible Officer on letterhead of the Company confirming the information specified in Section 3 including (a) the name and address of the transferee bank, (b) such transferee bank’s ABA number and (c) the account name and number into which the purchase price for the Notes is to be deposited.

4.11.

Proceedings and Documents.

All corporate and other proceedings in connection with the transactions contemplated by this Agreement and all documents and instruments incident to such transactions shall be satisfactory to such Purchaser and its special counsel, and such Purchaser and its special counsel shall have received all such counterpart originals or certified or other copies of such documents as such Purchaser or such special counsel may reasonably request.

5.	REPRESENTATIONS AND WARRANTIES OF THE COMPANY.

The Company represents and warrants to each Purchaser that:

5.1.

Organization; Power and Authority.

The Company is a corporation duly organized, validly existing and in good standing under the laws of its jurisdiction of incorporation, and is duly qualified as a foreign corporation and is in good standing in each jurisdiction in which such qualification is required by law, other than those jurisdictions as to which the failure to be so qualified or in good standing could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect. The Company has the corporate power and authority to own or hold under lease the properties it purports to own or hold under lease, to transact the business it transacts and proposes to transact, to execute and deliver this Agreement and the Notes and to perform the provisions hereof and thereof.

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5.2.

Authorization, Etc.

This Agreement and the Notes have been duly authorized by all necessary corporate action on the part of the Company, and this Agreement constitutes, and upon execution and delivery thereof each Note will constitute, a legal, valid and binding obligation of the Company enforceable against the Company in accordance with its terms, except as such enforceability may be limited by (i) applicable bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting the enforcement of creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

5.3.

Disclosure.

The Company, through its agents, J.P. Morgan Securities, Inc. has delivered to each Purchaser a copy of a Private Placement Memorandum, dated November, 2010 (the “ Memorandum ”), relating to the transactions contemplated hereby. The Memorandum fairly describes, in all material respects, the general nature of the business and principal properties of the Company and its Subsidiaries. This Agreement, the Memorandum and the documents, certificates or other writings delivered to the Purchasers by or on behalf of the Company in connection with the transactions contemplated hereby and identified in Schedule 5.3 (excluding estimates, financial projections and pro forma financial statements (the “ Projections ”)), and the financial statements listed in Schedule 5.5 (this Agreement, the Memorandum and such documents, certificates or other writings and such financial statements delivered to each Purchaser prior to December 15, 2010 being referred to, collectively, as the “ Disclosure Documents ”), taken as a whole, do not contain any untrue statement of a material fact or omit to state any material fact necessary to make the statements therein not misleading in light of the circumstances under which they were made. As to Projections, the Company represents only that such information was prepared in good faith based upon assumptions believed by it to be reasonable at the time. Except as disclosed in the Disclosure Documents, since December 31, 2009, there has been no change in the financial condition, operations, business, or properties of the Company or any Subsidiary except changes that individually or in the aggregate could not reasonably be expected to have a Material Adverse Effect.

5.4.

Organization and Ownership of Shares of Subsidiaries; Affiliates.

(a) Schedule 5.4 contains (except as noted therein) complete and correct lists (i) of the Company’s Subsidiaries, showing, as to each Subsidiary, the correct name thereof, the jurisdiction of its organization, and the percentage of shares of each class of its capital stock or similar equity interests outstanding owned by the Company and each other Subsidiary, (ii) of the Company’s Affiliates, other than Subsidiaries, and (iii) of the Company’s directors and senior officers.

(b) All of the outstanding shares of capital stock or similar equity interests of each Subsidiary shown in Schedule 5.4 as being owned by the Company and its Subsidiaries have been validly issued, are fully paid and nonassessable and are owned by the Company or another Subsidiary free and clear of any Lien (except as otherwise disclosed in Schedule 5.4).

(c) Each Subsidiary identified in Schedule 5.4 is a corporation or other legal entity duly organized, validly existing and in good standing under the laws of its jurisdiction of organization, and is duly qualified as a foreign corporation or other legal entity and is in good standing in each jurisdiction in which such qualification is required by law, other than those jurisdictions as to which the failure to be so qualified or in good standing could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect. Each such Subsidiary has the corporate or other power and authority to own or hold under lease the properties it purports to own or hold under lease and to transact the business it transacts and proposes to transact.

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(d) No Subsidiary is a party to, or otherwise subject to any legal, regulatory, contractual or other restriction (other than this Agreement, the agreements listed on Schedule 5.4 and customary limitations imposed by corporate law or similar statutes) restricting the ability of such Subsidiary to pay dividends out of profits or make any other similar distributions of profits to the Company or any of its Subsidiaries that owns outstanding shares of capital stock or similar equity interests of such Subsidiary.

5.5.

Financial Statements; Material Liabilities.

The Company has delivered to each Purchaser copies of the financial statements of the Company and its Subsidiaries listed on Schedule 5.5. All of said financial statements (including in each case the related schedules and notes) fairly present in all material respects the consolidated financial position of the Company and its Subsidiaries as of the respective dates specified in such Schedule and the consolidated results of their operations and cash flows for the respective periods so specified and have been prepared in accordance with GAAP consistently applied throughout the periods involved except as set forth in the notes thereto (subject, in the case of any interim financial statements, to normal year-end adjustments). The Company and its Subsidiaries do not have any Material liabilities that are not disclosed on such financial statements or otherwise disclosed in the Disclosure Documents.

5.6.

Compliance with Laws, Other Instruments, Etc.

The execution, delivery and performance by the Company of this Agreement and the Notes will not (a) contravene, result in any breach of, or constitute a default under, or result in the creation of any Lien in respect of any property of the Company or any Subsidiary under, any indenture, mortgage, deed of trust, loan, purchase or credit agreement, lease, corporate charter or by-laws, or any other Material agreement or instrument to which the Company or any Subsidiary is bound or by which the Company or any Subsidiary or any of their respective properties may be bound or affected, (b) conflict with or result in a breach of any of the terms, conditions or provisions of any order, judgment, decree, or ruling of any court, arbitrator or Governmental Authority applicable to the Company or any Subsidiary or (c) violate any provision of any statute or other rule or regulation of any Governmental Authority applicable to the Company or any Subsidiary.

5.7.

Governmental Authorizations, Etc.

No consent, approval or authorization of, or registration, filing or declaration with, any Governmental Authority is required to be obtained or made by the Company in connection with the execution, delivery or performance by the Company of this Agreement or the Notes.

-6-

5.8.

Litigation; Observance of Agreements, Statutes and Orders.

(a) There are no actions, suits, investigations or proceedings pending or, to the knowledge of the Company, threatened against or affecting the Company or any Subsidiary or any property of the Company or any Subsidiary in any court or before any arbitrator of any kind or before or by any Governmental Authority that, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect.

(b) Neither the Company nor any Subsidiary is in default under any term of any agreement or instrument to which it is a party or by which it is bound, or any order, judgment, decree or ruling of any court, arbitrator or Governmental Authority or is in violation of any applicable law, ordinance, rule or regulation (including without limitation Environmental Laws, the USA Patriot Act or any of the laws and regulations referred to in Section 5.16) of any Governmental Authority, which default or violation, individually or in the aggregate, could reasonably be expected to have a Material Adverse Effect.

5.9.

Taxes.

The Company and its Subsidiaries have filed all tax returns that are required to have been filed in any jurisdiction, and have paid all taxes shown to be due and payable on such returns and all other taxes and assessments levied upon them or their properties, assets, income or franchises, to the extent such taxes and assessments have become due and payable and before they have become delinquent, except for any taxes and assessments (a) the amount of which is not individually or in the aggregate Material or (b) the amount, applicability or validity of which is currently being contested in good faith by appropriate proceedings and with respect to which the Company or a Subsidiary, as the case may be, has established adequate reserves in accordance with GAAP. The Company knows of no basis for any other tax or assessment that could reasonably be expected to have a Material Adverse Effect. The charges, accruals and reserves on the books of the Company and its Subsidiaries in respect of Federal, state or other taxes for all fiscal periods are adequate. The Federal income tax liabilities of the Company and its Subsidiaries have been finally determined (whether by reason of completed audits or the statute of limitations having run) for all fiscal years up to and including the fiscal year ended December 31, 2008.

5.10.

Title to Property; Leases.

The Company and its Subsidiaries have good and defensible title to their respective properties that individually or in the aggregate are Material, including all such properties reflected in the most recent audited balance sheet referred to in Section 5.5 or purported to have been acquired by the Company or any Subsidiary after said date (except as sold or otherwise disposed of in compliance with this Agreement as if this Agreement had been in effect), in each case free and clear of Liens prohibited by this Agreement. All leases that individually or in the aggregate are Material are valid and subsisting and are in full force and effect in all material respects.

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5.11.

Licenses, Permits, Etc.

The Company and its Subsidiaries own or possess all licenses, permits, franchises, authorizations, patents, copyrights, proprietary software, service marks, trademarks and trade names, or rights thereto, that individually or in the aggregate are Material, without known conflict with the rights of others, except for those conflicts that, individually or in the aggregate, would not have a Material Adverse Effect.

5.12.

Compliance with ERISA.

(a) The Company and each ERISA Affiliate have operated and administered each Plan in compliance with all applicable laws except for such instances of noncompliance as have not resulted in and could not reasonably be expected to result in a Material Adverse Effect. Neither the Company nor any ERISA Affiliate has incurred any liability (other than premiums satisfied in due course) pursuant to Title I or IV of ERISA or the penalty or excise tax provisions of the Code relating to employee benefit plans (as defined in section 3 of ERISA), and no event, transaction or condition has occurred or exists that could reasonably be expected to result in the incurrence of any such liability by the Company or any ERISA Affiliate, or in the imposition of any Lien on any of the rights, properties or assets of the Company or any ERISA Affiliate, in either case pursuant to Title I or IV of ERISA or to such penalty or excise tax provisions or to the Pension Funding Rules or section 4068 of ERISA, other than such liabilities or Liens as would not be individually or in the aggregate Material.

(b) The present value of the aggregate benefit liabilities under each of the Plans that are subject to Title IV of ERISA (other than Multiemployer Plans), determined as of the end of such Plan’s most recently ended plan year on the basis of the actuarial assumptions specified for funding purposes in such Plan’s most recent actuarial valuation report, did not exceed the aggregate current value of the assets of such Plan allocable to such benefit liabilities in the case of any single Plan. The term “benefit liabilities” has the meaning specified in section 4001 of ERISA and the terms “current value” and “present value” have the meaning specified in section 3 of ERISA.

(c) The Company and its ERISA Affiliates have not incurred withdrawal liabilities (and are not subject to contingent withdrawal liabilities) under section 4201 or 4204 of ERISA in respect of Multiemployer Plans that individually or in the aggregate are Material.

(d) The expected postretirement benefit obligation (determined as of the last day of the Company’s most recently ended fiscal year in accordance with Financial Accounting Standards Board Accounting Standards Codification 715-60, without regard to liabilities attributable to continuation coverage mandated by section 4980B of the Code) of the Company and its Subsidiaries is not Material.

(e) The execution and delivery of this Agreement and the issuance and sale of the Notes hereunder will not involve any transaction that is subject to the prohibitions of section 406(a) of ERISA or in connection with which a tax could be imposed pursuant to section 4975(c)(1)(A)-(D) of the Code. The representation by the Company to each Purchaser in the first sentence of this Section 5.12(e) is made in reliance upon and subject to the accuracy of such Purchaser’s representation in Section 6.2 as to the sources of the funds used to pay the purchase price of the Notes to be purchased by such Purchaser.

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5.13.

Private Offering by the Company.

Neither the Company nor anyone acting on its behalf has offered the Notes or any similar securities for sale to, or solicited any offer to buy any of the same from, or otherwise approached or negotiated in respect thereof with, any person other than the Purchasers and other Institutional Investors (as defined in clause (c) to the definition of such term) totaling not more than 70 (inclusive of the Purchasers), each of which has been offered the Notes at a private sale for investment. Neither the Company nor anyone acting on its behalf has taken, or will take, any action that would subject the issuance or sale of the Notes to the registration requirements of Section 5 of the Securities Act or to the registration requirements of any securities or blue sky laws of any applicable jurisdiction.

5.14.

Use of Proceeds; Margin Regulations.

The Company will apply the proceeds of the sale of the Notes as set forth in the section of the Memorandum entitled “The Offering and Use of Proceeds”. No part of the proceeds from the sale of the Notes hereunder will be used, directly or indirectly, for the purpose of buying or carrying any margin stock within the meaning of Regulation U of the Board of Governors of the Federal Reserve System (12 CFR 221), or for the purpose of buying or carrying or trading in any securities under such circumstances as to involve the Company in a violation of Regulation X of said Board (12 CFR 224) or to involve any broker or dealer in a violation of Regulation T of said Board (12 CFR 220). Margin stock does not constitute more than 20% of the value of the consolidated assets of the Company and its Subsidiaries and the Company does not have any present intention that margin stock will constitute more than 20% of the value of such assets. As used in this Section, the terms “margin stock” and “purpose of buying or carrying” shall have the meanings assigned to them in said Regulation U.

5.15.

Existing Indebtedness; Future Liens

(a) Except as described therein, Schedule 5.15 sets forth a complete and correct list of all outstanding Indebtedness of the Company and its Subsidiaries as of September 30, 2010 (including a description of the obligors and obligees, principal amount outstanding and collateral therefor, if any, and Guaranty thereof, if any), since which date there has been no Material change in the amounts, interest rates, sinking funds, installment payments or maturities of the Indebtedness of the Company or its Subsidiaries. Neither the Company nor any Subsidiary is in default and no waiver of default is currently in effect, in the payment of any principal or interest on any Indebtedness of the Company or such Subsidiary and no event or condition exists with respect to any Indebtedness of the Company or any Subsidiary that would permit (or that with notice or the lapse of time, or both, would permit) one or more Persons to cause such Indebtedness to become due and payable before its stated maturity or before its regularly scheduled dates of payment.

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(b) Except as disclosed in Schedule 5.15, neither the Company nor any Subsidiary has agreed or consented to cause or permit in the future (upon the happening of a contingency or otherwise) any of its property, whether now owned or hereafter acquired, to be subject to a Lien not permitted by Section 10.5.

(c) Neither the Company nor any Subsidiary is a party to, or otherwise subject to any provision contained in, any instrument evidencing Indebtedness of the Company or such Subsidiary, any agreement relating thereto or any other agreement (including, but not limited to, its charter or other organizational document) which limits the amount of, or otherwise imposes restrictions on the incurring of, Indebtedness of the Company, except as specifically indicated in Schedule 5.15.

5.16.

Foreign Assets Control Regulations, Etc.

(a) Neither the Company nor any Affiliated Entity is (i) a Person whose name appears on the list of Specially Designated Nationals and Blocked Persons published by the Office of Foreign Assets Control, U.S. Department of Treasury (“ OFAC ”) (an “ OFAC Listed Person ”), (ii) a Person that is otherwise a sanctions target of the OFAC sanctions programs or (iii) a department, agency or instrumentality of, or is otherwise controlled by or acting on behalf of, directly or indirectly, (x) any OFAC Listed Person or Person that is otherwise a sanctions target or (y) the government of a country subject to comprehensive U.S. economic sanctions administered by OFAC, currently Iran, Sudan, Cuba and Syria (each OFAC Listed Person and each other entity described in clause (ii) and (iii), a “ Blocked Person ”).

(b) No part of the proceeds from the sale of the Notes hereunder constitutes or will constitute funds obtained on behalf of any Blocked Person or will otherwise be used, directly by the Company or indirectly through any Affiliated Entity, in connection with any investment in, or any transactions or dealings with, any Blocked Person.

(c) To the Company’s actual knowledge after making due inquiry, neither the Company nor any Affiliated Entity (i) is under investigation by any Governmental Authority for, or has been charged with, or convicted of, money laundering, drug trafficking, terrorist-related activities or other money laundering predicate crimes under any applicable law (collectively, “ Anti-Money Laundering Laws ”), (ii) has been assessed civil penalties under any Anti-Money Laundering Laws or (iii) has had any of its funds seized or forfeited in an action under any Anti-Money Laundering Laws. The Company has taken reasonable measures appropriate to the circumstances (in any event as required by applicable law), to ensure that the Company and each Affiliated Entity is and will continue to be in compliance with all applicable Anti-Money Laundering Laws.

(d) No part of the proceeds from the sale of the Notes hereunder will be used, directly or indirectly, for any improper payments to any governmental official or employee, political party, official of a political party, candidate for political office, official of any public international organization or anyone else acting in an official capacity, in order to obtain any improper advantage. The Company has taken reasonable measures appropriate to the circumstances (in any event as required by applicable law), to ensure that the Company and each Affiliated Entity is and will continue to be in compliance with all applicable anti-corruption laws and regulations.

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5.17.

Status under Certain Statutes.

(a) Neither the Company nor any Subsidiary is subject to regulation under the Investment Company Act of 1940, as amended.

(b) Neither the Company nor any Subsidiary is a “public utility,” as that term is defined under the Federal Power Act, as amended, and the regulations publicly promulgated thereunder (collectively, the “ FPA ”) by the Federal Energy Regulatory Commission (“ FERC ”). Following the consummation of the transactions contemplated by this Agreement, solely as a result of the execution and delivery hereof and thereof, no Purchaser or holder of Notes shall be subject to regulation as a “public utility” or as an “affiliate” thereof under the FPA.

5.18.

Environmental Matters.

Except for such matters that individually, or in the aggregate could not reasonably be expected to have a Material Adverse Effect, neither the Company nor any of its Subsidiaries (a) has failed to comply with any Environmental Law or to obtain, maintain or comply with any permit, license or other approval required under any Environmental Law, (b) has become subject to any Environmental Liability, (c) has received any notice of any claim with respect to any Environmental Liability or (d) knows of any basis for any Environmental Liability.

5.19.

Ranking of Obligations.

The Company’s payment obligations under this Agreement and the Notes will, upon issuance of the Notes, rank at least pari passu , without preference of priority, with all other unsecured and unsubordinated Indebtedness of the Company.

6.	REPRESENTATIONS OF THE PURCHASERS.

6.1.

Purchase for Investment.

Each Purchaser severally represents that it is purchasing the Notes for its own account or for one or more separate accounts maintained by such Purchaser or for the account of one or more pension or trust funds and not with a view to the distribution thereof, provided that the disposition of such Purchaser’s or their property shall at all times be within such Purchaser’s or their control. Each Purchaser understands that the Notes have not been registered under the Securities Act and may be resold only if registered pursuant to the provisions of the Securities Act or if an exemption from registration is available, except under circumstances where neither such registration nor such an exemption is required by law, and that the Company is not required to register the Notes.

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6.2.

Source of Funds.

Each Purchaser severally represents that at least one of the following statements is an accurate representation as to each source of funds (a “ Source ”) to be used by such Purchaser to pay the purchase price of the Notes to be purchased by such Purchaser hereunder:

(a) the Source is an “insurance company general account” (as the term is defined in the United States Department of Labor’s Prohibited Transaction Exemption (“ PTE ”) 95-60) in respect of which the amount of the reserves and liabilities (as defined by the annual statement for life insurance companies approved by the National Association of Insurance Commissioners (the “ NAIC Annual Statement ”)) for the general account contract(s) held by or on behalf of any employee benefit plan together with the amount of the reserves and liabilities for the general account contract(s) held by or on behalf of any other employee benefit plans maintained by the same employer (or affiliate thereof as defined in PTE 95-60) or by the same employee organization in the general account do not exceed 10% of the total reserves and liabilities of the general account (exclusive of separate account liabilities) plus surplus as set forth in the NAIC Annual Statement filed with such Purchaser’s state of domicile; or

(b) the Source is a separate account of an insurance company that is maintained solely in connection with such Purchaser’s fixed contractual obligations of the insurance company under which the amounts payable, or credited, to any employee benefit plan (or its related trust) that has any interest in such separate account (or to any participant or beneficiary of such plan (including any annuitant)) are not affected in any manner by the investment performance of the separate account; or

(c) the Source is either (i) an insurance company pooled separate account, within the meaning of PTE 90-1 or (ii) a bank collective investment fund, within the meaning of the PTE 91-38 and, except as disclosed by such Purchaser to the Company in writing pursuant to this clause (c), no employee benefit plan or group of plans maintained by the same employer or employee organization beneficially owns more than 10% of all assets allocated to such pooled separate account or collective investment fund; or

(d) the Source constitutes assets of an “investment fund” (within the meaning of Part V of PTE 84-14 (the “ QPAM Exemption ”)) managed by a “qualified professional asset manager” or “QPAM” (within the meaning of Part V of the QPAM Exemption), no employee benefit plan’s assets that are included in such investment fund, when combined with the assets of all other employee benefit plans established or maintained by the same employer or by an affiliate (within the meaning of Section V(c)(1) of the QPAM Exemption) of such employer or by the same employee organization and managed by such QPAM, represent more than 20% of the total client assets managed by such QPAM, the conditions of Part I(c) and (g) of the QPAM Exemption are satisfied, neither the QPAM nor a person controlling or controlled by the QPAM (applying the definition of “control” in Section V(e) of the QPAM Exemption) owns a 5% or more interest in the Company and (i) the identity of such QPAM and (ii) the names of all employee benefit plans whose assets are included in such investment fund have been disclosed to the Company in writing pursuant to this clause (d); or

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(e) the Source constitutes assets of a “plan(s)” (within the meaning of Section IV of PTE 96-23 (the “ INHAM Exemption ”)) managed by an “in-house asset manager” or “INHAM” (within the meaning of Part IV of the INHAM Exemption), the conditions of Part I(a), (g) and (h) of the INHAM Exemption are satisfied, neither the INHAM nor a person controlling or controlled by the INHAM (applying the definition of “control” in Section IV(d) of the INHAM Exemption) owns a 5% or more interest in the Company and (i) the identity of such INHAM and (ii) the name(s) of the employee benefit plan(s) whose assets constitute the Source have been disclosed to the Company in writing pursuant to this clause (e); or

(f) the Source is a governmental plan; or

(g) the Source is one or more employee benefit plans, or a separate account or trust fund comprised of one or more employee benefit plans, each of which has been identified to the Company in writing pursuant to this clause (g); or

(h) the Source does not include assets of any employee benefit plan, other than a plan exempt from the coverage of ERISA and section 4975 of the Code.

As used in this Section 6.2, the terms “employee benefit plan,” “governmental plan,” and “separate account” shall have the respective meanings assigned to such terms in section 3 of ERISA, and the term “employee benefit plan” shall mean an “employee benefit plan” within the meaning of section 3(3) of ERISA and/or a “plan” within the meaning of section 4975(e)(1) of the Code.

7.	INFORMATION AS TO COMPANY.,

7.1.

Financial and Business Information.

The Company shall deliver to each holder of Notes that is an Institutional Investor:

(a) Quarterly Statements — within 60 days (or such shorter period as is 15 days greater than the period applicable to the filing of the Company’s Quarterly Report on Form 10-Q (the “ Form 10-Q ”) with the SEC regardless of whether the Company is subject to the filing requirements thereof) after the end of each quarterly fiscal period in each fiscal year of the Company (other than the last quarterly fiscal period of each such fiscal year), duplicate copies of,

(i) a consolidated balance sheet of the Company and its Subsidiaries as at the end of such quarter, and

(ii) consolidated statements of income, changes in shareholders’ equity and cash flows of the Company and its Subsidiaries, for such quarter and (in the case of the second and third quarters) for the portion of the fiscal year ending with such quarter,

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setting forth in each case in comparative form the figures for the corresponding periods in the previous fiscal year, all in reasonable detail, prepared in accordance with GAAP applicable to quarterly financial statements generally, and certified by a Senior Financial Officer as fairly presenting, in all material respects, the financial position of the companies being reported on and their results of operations and cash flows, subject to changes resulting from year-end adjustments, provided that delivery within the time period specified above of copies of the Company’s Form 10-Q prepared in compliance with the requirements therefor and filed with the SEC shall be deemed to satisfy the requirements of this Section 7.1(a), provided, further, that the Company shall be deemed to have made such delivery of such Form 10-Q if it shall have timely made such Form 10-Q available on “EDGAR” and on its home page on the worldwide web (at the date of this Agreement located at: http//www.cabotog.com) and shall have given each Purchaser prior notice of such availability on EDGAR and on its home page in connection with each delivery (such availability and notice thereof being referred to as “ Electronic Delivery ”);

(b) Annual Statements — within 90 days (or such shorter period as is 15 days greater than the period applicable to the filing of the Company’s Annual Report on Form 10-K (the “ Form 10-K ”) with the SEC regardless of whether the Company is subject to the filing requirements thereof) after the end of each fiscal year of the Company, duplicate copies of,

(i) a consolidated balance sheet of the Company and its Subsidiaries as at the end of such year, and

(ii) consolidated statements of income, changes in shareholders’ equity and cash flows of the Company and its Subsidiaries for such year, setting forth in each case in comparative form the figures for the previous fiscal year, all in reasonable detail, prepared in accordance with GAAP, and accompanied by an opinion thereon of independent public accountants of recognized national standing, which opinion shall state that such financial statements present fairly, in all material respects, the financial position of the companies being reported upon and their results of operations and cash flows and have been prepared in conformity with GAAP, and that the examination of such accountants in connection with such financial statements has been made in accordance with generally accepted auditing standards, and that such audit provides a reasonable basis for such opinion in the circumstances,

provided that the delivery within the time period specified above of the Company’s Form 10-K for such fiscal year (together with the Company’s annual report to shareholders, if any, prepared pursuant to Rule 14a-3 under the Exchange Act) prepared in accordance with the requirements therefor and filed with the SEC shall be deemed to satisfy the requirements of this Section 7.1(b), provided, further, that the Company shall be deemed to have made such delivery of such Form 10-K if it shall have timely made Electronic Delivery thereof;

(c) SEC and Other Reports — promptly upon their becoming available, one copy of each regular or periodic report, each registration statement (without exhibits except as expressly requested by such holder and any registration statements on Form S-8 or its equivalent), and each prospectus and all amendments thereto filed by the Company or any Subsidiary with the SEC;

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(d) Notice of Default or Event of Default — promptly, and in any event within five days after a Responsible Officer becoming aware of the existence of any Default or Event of Default or that any Person has given any notice or taken any action with respect to a claimed default hereunder or that any Person has given any notice or taken any action with respect to a claimed default of the type referred to in Section 11(f), a written notice specifying the nature and period of existence thereof and what action the Company is taking or proposes to take with respect thereto;

(e) ERISA Matters — promptly, and in any event within five days after a Responsible Officer becoming aware of any of the following, a written notice setting forth the nature thereof and the action, if any, that the Company or an ERISA Affiliate proposes to take with respect thereto:

(i) with respect to any Plan, any reportable event, as defined in section 4043(c) of ERISA and the regulations thereunder, for which notice thereof has not been waived pursuant to such regulations as in effect on the date hereof; or

(ii) the taking by the PBGC of steps to institute, or the threatening by the PBGC of the institution of, proceedings under section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan, or the receipt by the Company or any ERISA Affiliate of a notice from a Multi-employer Plan that such action has been taken by the PBGC with respect to such Multi-employer Plan; or

(iii) any event, transaction or condition that could result in the incurrence of any liability by the Company or any ERISA Affiliate pursuant to Title I or IV of ERISA or the penalty or excise tax provisions of the Code relating to employee benefit plans, or in the imposition of any Lien on any of the rights, properties or assets of the Company or any ERISA Affiliate pursuant to Title I or IV of ERISA, the Pension Funding Rules, or such penalty or excise tax provisions, if such liability or Lien, taken together with any other such liabilities or Liens then existing, could reasonably be expected to have a Material Adverse Effect;

(f) Notices from Governmental Authority — promptly, and in any event within 30 days of receipt thereof, copies of any notice to the Company or any Subsidiary from any Federal or state Governmental Authority relating to any order, ruling, statute or other law or regulation that could reasonably be expected to have a Material Adverse Effect;

(g) Engineering Reports — by April 10th of each year, a report in form and substance reasonably satisfactory to the Required Holders prepared by or under the supervision of a petroleum engineer who may be an employee of the Company, which shall evaluate all net Proved Reserves owned by the Company and its Subsidiaries as of the preceding December 31st and which shall set forth the information necessary to determine the Present Value of Proved Reserves as of such date, together with a review report thereon in form and substance reasonably satisfactory to the Required Holders by Miller & Lents, Ltd. or other independent petroleum engineers of nationally recognized standing; and

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(h) Borrowing Base Reports — promptly, and in any event within three (3) Business Days of receipt thereof, a copy of each New Borrowing Base Notice (as defined in the Bank Credit Agreement) (or similar borrowing base notice under any successor agreement) received by the Company; and

(i) Requested Information — with reasonable promptness, such other data and information relating to the business, operations, affairs, financial condition, assets or properties of the Company or any of its Subsidiaries (including, but without limitation, actual copies of the Company’s Form 10-Q and Form 10-K) or relating to the ability of the Company to perform its obligations hereunder and under the Notes as from time to time may be reasonably requested by any such holder of Notes.

7.2.

Officer’s Certificate.

Each set of financial statements delivered to a holder of Notes pursuant to Section 7.1(a) or Section 7.1(b) shall be accompanied by a certificate of a Senior Financial Officer setting forth (which, in the case of Electronic Delivery of any such financial statements, shall be by separate concurrent delivery of such certificate to each holder of Notes):

(a) Covenant Compliance — the information (including detailed calculations) required in order to establish whether the Company was in compliance with the requirements of Sections 10.7, 10.8 and 10.9, inclusive, during the quarterly or annual period covered by the statements then being furnished (including with respect to each such Section, where applicable, the calculations of the maximum or minimum amount, ratio or percentage, as the case may be, permissible under the terms of such Sections, and the calculation of the amount, ratio or percentage then in existence); and

(b) Event of Default — a statement that such Senior Financial Officer has reviewed the relevant terms hereof and has made, or caused to be made, under his or her supervision, a review of the transactions and conditions of the Company and its Subsidiaries from the beginning of the quarterly or annual period covered by the statements then being furnished to the date of the certificate and that such review shall not have disclosed the existence during such period of any condition or event that constitutes a Default or an Event of Default or, if any such condition or event existed or exists (including, without limitation, any such event or condition resulting from the failure of the Company or any Subsidiary to comply with any Environmental Law), specifying the nature and period of existence thereof and what action the Company shall have taken or proposes to take with respect thereto.

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(c) Additional Information — a list of all obligors, borrowers and guarantors under the Bank Credit Agreement (or a statement that the list of obligors, borrowers and guarantors under the Bank Credit Agreement most recently delivered pursuant to this Section 7.2 remains unchanged) together with a copy of each guaranty, joinder agreement or such other agreement evidencing its obligations thereunder executed in connection therewith or in connection with this Agreement since the date of the last certificate required under this section to be delivered to each holder of Notes.

7.3.

Visitation.

The Company shall permit the representatives of each holder of Notes that is an Institutional Investor:

(a) No Default — if no Default or Event of Default then exists, at the expense of such holder and upon reasonable prior notice to the Company, to visit the principal executive office of the Company, to discuss the affairs, finances and accounts of the Company and its Subsidiaries with the Company’s officers, and (with the consent of the Company, which consent will not be unreasonably withheld) its independent public accountants, and (with the consent of the Company, which consent will not be unreasonably withheld) to visit the other offices and properties of the Company and each Subsidiary, all at such reasonable times and as often as may be reasonably requested in writing; provided that each holder shall not be entitled to more than one visitation during any fiscal year; and

(b) Default — if a Default or Event of Default then exists, at the expense of the Company to visit and inspect any of the offices or properties of the Company or any Subsidiary during normal business hours, to examine all their respective books of account, records, reports and other papers, to make copies and extracts therefrom, and to discuss their respective affairs, finances and accounts with their respective officers and independent public accountants (and by this provision the Company authorizes said accountants to discuss the affairs, finances and accounts of the Company and its Subsidiaries), all at such times and as often as may be requested.

8.	PAYMENT AND PREPAYMENT OF THE NOTES.

8.1.

Maturity.

As provided therein, the entire unpaid principal balance of the Notes shall be due and payable on the stated maturity date thereof.

8.2.

Optional Prepayments with Make-Whole Amount.

The Company may, at its option, upon notice as provided below, prepay at any time all, or from time to time any part of, the Notes, (but if in part, in an amount not less than $1,000,000 or such lesser amount as shall then be outstanding), at 100% of the principal amount so prepaid, and the Make-Whole Amount determined for the prepayment date with respect to such principal amount. The Company will give each holder of Notes written notice of each optional prepayment under this Section 8.2 not less than 30 days and not more than 60 days prior to the date fixed for such prepayment. Each such notice shall specify such date (which shall be a Business Day), the aggregate principal amount of the Notes to be prepaid on such date, the principal amount of each Note held by such holder to be prepaid (determined in accordance with Section 8.5), and the interest to be paid on the prepayment date with respect to such principal amount being prepaid, and shall be accompanied by a certificate of a Senior Financial Officer as to the estimated Make-Whole Amount due in connection with such prepayment (calculated as if the date of such notice were the date of the prepayment), setting forth the details of such computation. Two Business Days prior to such prepayment, the Company shall deliver to each holder of Notes a certificate of a Senior Financial Officer specifying the calculation of such Make-Whole Amount as of the specified prepayment date.

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8.3.

Prepayment of Notes Upon Change of Control.

(a) Notice of Change of Control or Control Event; Offer to Prepay if Change of Control Has Occurred . The Company will, within 5 Business Days after any Responsible Officer has knowledge of the occurrence of any Change of Control or Control Event (subject to extension if necessary in order to comply with applicable law), give notice of such Change of Control or Control Event to each holder of Notes. If a Change of Control has occurred, such notice shall contain and constitute an offer to prepay Notes as described in paragraph (b) of this Section 8.3 and shall be accompanied by the certificate described in paragraph (e) of this Section 8.3.

(b) Offer to Prepay; Time for Payment . The offer to prepay Notes contemplated by paragraph (a) of this Section 8.3 shall be an offer to prepay, in accordance with and subject to this Section 8.3, all, but not less than all, of the Notes held by each holder (in the case of this Section 8.3 only, “holder” in respect of any Note registered in the name of a nominee for a disclosed beneficial owner shall mean such beneficial owner) on a date specified in such offer (the “ Proposed Prepayment Date ”). The Proposed Prepayment Date shall not be less than 15 days and not more than 60 days after the date of such offer (if the Proposed Prepayment Date shall not be specified in the offer, the Proposed Prepayment Date shall be the 45th day after the date of such offer).

(c) Acceptance; Rejection . A holder of Notes may accept the offer to prepay made pursuant to this Section 8.3 by causing a notice of such acceptance to be delivered to the Company at least 5 days prior to the Proposed Prepayment Date. A failure by a holder of Notes to respond to an offer to prepay made pursuant to this Section 8.3, or to accept an offer as to all of the Notes held by the holder, within such time period shall be deemed to constitute a rejection of such offer by such holder.

(d) Prepayment . Prepayment of the Notes to be prepaid pursuant to this Section 8.3 shall be at 100% of the principal amount of such Notes, together with interest on such Notes accrued to the date of prepayment. On the Business Day preceding the date of prepayment, the Company shall deliver to each holder of Notes being prepaid a statement setting forth the details of the computation of such amount. The prepayment shall be made on the Proposed Prepayment Date.

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(e) Officer’s Certificate . Each offer to prepay the Notes pursuant to this Section 8.3 shall be accompanied by a certificate, executed by a Senior Financial Officer of the Company and dated the date of such offer, specifying: (i) the Proposed Prepayment Date, (ii) that such offer is made pursuant to this Section 8.3, (iii) that the entire principal amount of each Note is offered to be prepaid, (iv) the interest that would be due on each Note offered to be prepaid, accrued to the Proposed Prepayment Date, (v) that the conditions of this Section 8.3 required to be fulfilled prior to the giving of such notice have been fulfilled and (vi) in reasonable detail, the nature and date of the Change of Control.

8.4.

Prepayment in Connection with a Disposition.

(a) Notice and Offer . In the event any Debt Prepayment Application is to be used to make an offer (a “ Transfer Prepayment Offer ”) to prepay Notes pursuant to Section 10.6 of this Agreement (a “ Debt Prepayment Transfer ”), the Company will give written notice of such Debt Prepayment Transfer to each holder of Notes. Such written notice shall contain, and such written notice shall constitute, an irrevocable offer to prepay, at the election of each holder, a portion of the Notes held by such holder equal to such holder’s Ratable Portion of the net proceeds in respect of such Debt Prepayment Transfer on a date specified in such notice (the “ Transfer Prepayment Date ”) that is not less than thirty (30) days and not more than sixty (60) days after the date of such notice, together with interest on the amount to be so prepaid accrued to the Transfer Prepayment Date. If the Transfer Prepayment Date shall not be specified in such notice, the Transfer Prepayment Date shall be the thirtieth (30th) day after the date of such notice.

(b) Acceptance and Payment . To accept such Transfer Prepayment Offer, a holder of Notes shall cause a notice of such acceptance to be delivered to the Company at least 5 days prior to the Transfer Prepayment Date, provided, that failure to accept such offer in writing within such time period shall be deemed to constitute a rejection of the Transfer Prepayment Offer. If so accepted by any holder of a Note, such offered prepayment (equal to not less than such holder’s Ratable Portion of the net proceeds in respect of such Debt Prepayment Transfer) shall be due and payable on the Transfer Prepayment Date. Such offered prepayment shall be made at one hundred percent (100%) of the principal amount of such Notes being so prepaid, together with interest on such principal amount then being prepaid accrued to the Transfer Prepayment Date determined as of the date of such prepayment.

(c) Other Terms . Each offer to prepay the Notes pursuant to this Section 8.4 shall be accompanied by a certificate, executed by a Senior Financial Officer of the Company and dated the date of such offer, specifying (i) the Transfer Prepayment Date, (ii) the net proceeds in respect of the applicable Debt Prepayment Transfer, (iii) that such offer is being made pursuant to Section 8.4 and Section 10.6 of this Agreement, (iv) the principal amount of each Note offered to be prepaid, (v) the interest that would be due on each Note offered to be prepaid, accrued to the Transfer Prepayment Date and (vi) in reasonable detail, the nature of the Disposition giving rise to such Debt Prepayment Transfer and certifying that no Default or Event of Default exists or would exist after giving effect to the prepayment contemplated by such offer.

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(d) Notice Concerning Status of Holders of Notes . Promptly after each Transfer Prepayment Date and the making of all prepayments contemplated on such Transfer Prepayment Date under this Section 8.4 (and, in any event, within thirty (30) days thereafter), the Company shall deliver to each holder of Notes a certificate signed by a Senior Financial Officer of the Company containing a list of the then current holders of Notes (together with their addresses) and setting forth as to each such holder the outstanding principal amount of Notes held by such holder at such time.

8.5.

Allocation of Partial Prepayments.

In the case of each partial prepayment of the Notes pursuant to Section 8.2, the principal amount of the Notes to be prepaid shall be allocated among all of the Notes at the time outstanding in proportion, as nearly as practicable, to the respective unpaid principal amounts thereof not theretofore called for prepayment, without regard to the Series of Notes.

8.6.

Maturity; Surrender, Etc.

In the case of each prepayment of Notes pursuant to this Section 8, the principal amount of each Note to be prepaid shall mature and become due and payable on the date fixed for such prepayment (which shall be a Business Day), together with interest on such principal amount accrued to such date and the applicable Make-Whole Amount, if any. From and after such date, unless the Company shall fail to pay such principal amount when so due and payable, together with the interest and Make-Whole Amount, if any, as aforesaid, interest on such principal amount shall cease to accrue. Any Note paid or prepaid in full shall be surrendered to the Company and cancelled and shall not be reissued, and no Note shall be issued in lieu of any prepaid principal amount of any Note.

8.7.

Purchase of Notes.

The Company will not and will not permit any Affiliate to purchase, redeem, prepay or otherwise acquire, directly or indirectly, any of the outstanding Notes except (a) upon the payment or prepayment of the Notes in accordance with the terms of this Agreement and the Notes or (b) pursuant to an offer to purchase made by the Company or an Affiliate pro rata to the holders of all Notes at the time outstanding upon the same terms and conditions. Any such offer shall provide each holder with sufficient information to enable it to make an informed decision with respect to such offer, and shall remain open for at least 30 Business Days. If the holders of more than 25% of the principal amount of the Notes then outstanding accept such offer, the Company shall promptly notify the remaining holders of such fact and the expiration date for the acceptance by holders of Notes of such offer shall be extended by the number of days necessary to give each such remaining holder at least 10 Business Days from its receipt of such notice to accept such offer. The Company will promptly cancel all Notes acquired by it or any Affiliate pursuant to any payment or prepayment of Notes pursuant to any provision of this Agreement and no Notes may be issued in substitution or exchange for any such Notes.

8.8.

Make-Whole Amount.

“ Make-Whole Amount ” means, with respect to any Note of any Series, an amount equal to the excess, if any, of the Discounted Value of the Remaining Scheduled Payments with respect to the Called Principal of such Note of such Series over the amount of such Called Principal, provided that the Make-Whole Amount may in no event be less than zero. For the purposes of determining the Make-Whole Amount, the following terms have the following meanings:

“ Called Principal ” means, with respect to any Note of any Series, the principal of such Note that is to be prepaid pursuant to Section 8.2, or has become or is declared to be immediately due and payable pursuant to Section 12.1, as the context requires.

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“ Discounted Value ” means, with respect to the Called Principal of any Note of any Series, the amount obtained by discounting all Remaining Scheduled Payments with respect to such Called Principal from their respective scheduled due dates to the Settlement Date with respect to such Called Principal, in accordance with accepted financial practice and at a discount factor (applied on the same periodic basis as that on which interest on such Series of Notes is payable) equal to the Reinvestment Yield with respect to such Called Principal.

“ Reinvestment Yield ” means, with respect to the Called Principal of any Note of any Series, 0.50% over the yield to maturity implied by (i) the yields reported as of 10:00 a.m. (New York City time) on the second Business Day preceding the Settlement Date with respect to such Called Principal, on the display designated as “Page PX1” (or such other display as may replace Page PX1) on Bloomberg Financial Markets for the most recently issued actively traded on the run U.S. Treasury securities having a maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date, or (ii) if such yields are not reported as of such time or the yields reported as of such time are not ascertainable (including by way of interpolation), the Treasury Constant Maturity Series Yields reported, for the latest day for which such yields have been so reported as of the second Business Day preceding the Settlement Date with respect to such Called Principal, in Federal Reserve Statistical Release H.15 (or any comparable successor publication) for U.S. Treasury securities having a constant maturity equal to the Remaining Average Life of such Called Principal as of such Settlement Date.

In the case of each determination under clause (i) or clause (ii), as the case may be, of the preceding paragraph, such implied yield will be determined, if necessary, by (a) converting U.S. Treasury bill quotations to bond equivalent yields in accordance with accepted financial practice and (b) interpolating linearly between (1) the applicable U.S. Treasury security with the maturity closest to and greater than such Remaining Average Life and (2) the applicable U.S. Treasury security with the maturity closest to and less than such Remaining Average Life. The Reinvestment Yield shall be rounded to the number of decimal places as appears in the interest rate of the applicable Series of Note.

“ Remaining Average Life ” means, with respect to any Called Principal of any Series of Notes, the number of years (calculated to the nearest one-twelfth year) obtained by dividing (i) such Called Principal into (ii) the sum of the products obtained by multiplying (a) the principal component of each Remaining Scheduled Payment with respect to such Called Principal by (b) the number of years (calculated to the nearest one-twelfth year) that will elapse between the Settlement Date with respect to such Called Principal and the scheduled due date of such Remaining Scheduled Payment.

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“ Remaining Scheduled Payments ” means, with respect to the Called Principal of any Note of any Series, all payments of such Called Principal and interest thereon that would be due after the Settlement Date with respect to such Called Principal if no payment of such Called Principal were made prior to its scheduled due date, provided that if such Settlement Date is not a date on which interest payments are due to be made under the terms of the Notes of such Series, then the amount of the next succeeding scheduled interest payment will be reduced by the amount of interest accrued to such Settlement Date and required to be paid on such Settlement Date pursuant to Section 8.2 or Section 12.1.

“ Settlement Date ” means, with respect to the Called Principal of any Note of any Series, the date on which such Called Principal is to be prepaid pursuant to Section 8.2, or has become or is declared to be immediately due and payable pursuant to Section 12.1, as the context requires.

9.	AFFIRMATIVE COVENANTS.

The Company covenants that so long as any of the Notes are outstanding:

9.1.

Compliance with Law.

Without limiting Section 10.4, the Company will, and will cause each of its Subsidiaries to, comply with all laws, ordinances or governmental rules or regulations to which each of them is subject, including, without limitation, ERISA, Environmental Laws, the USA Patriot Act and the laws and regulations referred to in Section 5.16, and will obtain and maintain in effect all licenses, certificates, permits, franchises and other governmental authorizations necessary to the ownership of their respective properties or to the conduct of their respective businesses, in each case to the extent necessary to ensure that non-compliance with such laws, ordinances or governmental rules or regulations or failures to obtain or maintain in effect such licenses, certificates, permits, franchises and other governmental authorizations could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

9.2.

Insurance.

The Company will, and will cause each of its Subsidiaries to, maintain, with financially sound and reputable insurers, insurance with respect to their respective properties and businesses against such casualties and contingencies, of such types, on such terms and in such amounts (including deductibles, co-insurance and self-insurance, if adequate reserves are maintained with respect thereto) as is customary in the case of entities of established reputations engaged in the same or a similar business and similarly situated.

9.3.

Maintenance of Properties.

The Company will, and will cause each of its Subsidiaries to, maintain and keep, or cause to be maintained and kept, their respective properties in good repair, working order and condition (other than ordinary wear and tear), so that the business carried on in connection therewith may be properly conducted at all times, provided that this Section shall not prevent the Company or any Subsidiary from discontinuing the operation and the maintenance of any of its properties if such discontinuance is desirable in the conduct of its business and the Company has concluded that such discontinuance could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

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9.4.

Payment of Taxes and Claims.

The Company will, and will cause each of its Subsidiaries to, file all tax returns required to be filed in any jurisdiction and to pay and discharge all taxes shown to be due and payable on such returns and all other taxes, assessments, governmental charges, or levies imposed on them or any of their properties, assets, income or franchises, to the extent the same have become due and payable and before they have become delinquent and all claims for which sums have become due and payable that have or might become a Lien on properties or assets of the Company or any Subsidiary, provided that neither the Company nor any Subsidiary need pay any such tax, assessment, charge, levy or claim if (a) the amount, applicability or validity thereof is contested by the Company or such Subsidiary on a timely basis in good faith and in appropriate proceedings, and the Company or a Subsidiary has established adequate reserves therefor in accordance with GAAP on the books of the Company or such Subsidiary or (b) the nonpayment of all such taxes, assessments, charges, levies and claims in the aggregate could not reasonably be expected to have a Material Adverse Effect.

9.5.

Corporate Existence, Etc.

Subject to Section 10.2, the Company will at all times preserve and keep in full force and effect its corporate existence; provided that the Company may convert to a form other than a corporate form so long as (x) no Change of Control shall result therefrom and (y) such successor (i) shall have executed and delivered, in form and substance reasonably satisfactory to the Required Holders, to each holder of any Notes its assumption of the due and punctual performance and observance of each covenant and condition of this Agreement and the Notes, and (ii) shall have caused to be delivered to each holder of any Notes an opinion of nationally recognized independent counsel, or other independent counsel reasonably satisfactory to the Required Holders, to the effect that all agreements or instruments effecting such assumption are enforceable in accordance with their terms and comply with the terms of this Section 9.5. Subject to Section 10.2, the Company will at all times preserve and keep in full force and effect the corporate existence of each of its Subsidiaries (unless merged into the Company or a Wholly-Owned Subsidiary) and all rights and franchises of the Company and its Subsidiaries unless, in the good faith judgment of the Company, the termination of or failure to preserve and keep in full force and effect such corporate existence, right or franchise could not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

9.6.

Books and Records.

The Company will, and will cause each of its Subsidiaries to, maintain proper books of record and account in conformity with GAAP and all applicable requirements of any Governmental Authority having legal or regulatory jurisdiction over the Company or such Subsidiary, as the case may be.

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9.7.

Ranking of Obligations.

The Company will ensure that its payment obligations under this Agreement and the Notes will at times rank at least pari passu , without preference or priority, with all other unsecured unsubordinated Debt of the Company.

9.8.

Subsidiary Guaranty; Release of Guaranties.

(a) Subsidiary Guarantors . The Company will cause each Subsidiary that, on or after the date of the Closing, is or becomes a borrower or guarantor of Indebtedness in respect of the Bank Credit Agreement, on the date of Closing or within 10 Business Days of its thereafter becoming a co-obligor, borrower or a guarantor of Indebtedness in respect of the Bank Credit Agreement to execute and deliver or become a party to a guaranty agreement in form and substance reasonably satisfactory to the Required Holders (the “ Subsidiary Guaranty ”), and shall deliver to each holder of Notes:

(i) an executed counterpart of the Subsidiary Guaranty, or, if a Subsidiary Guaranty has been previously executed and delivered, an executed counterpart of a joinder thereto;

(ii) copies of such directors’ or other authorizing resolutions, charter, bylaws and other constitutive documents of such Subsidiary as the Required Holders may reasonably request; and

(iii) an opinion of independent counsel reasonably satisfactory to the Required Holders and an opinion of in-house counsel to the Company, in each case consistent with the opinions provided to the Purchasers at the time of Closing covering the authorization, execution, delivery, compliance with law, no conflict with other documents, no consents and enforceability against such Subsidiary.

(b) Release of Subsidiary Guarantor . Each holder of a Note will release and discharge from the Subsidiary Guaranty a Subsidiary Guarantor, immediately and without any further act, upon (i) the Disposition of such Subsidiary Guarantor by the Company in compliance with Section 10.6 or the dissolution of such Subsidiary Guarantor and the assumption of its liabilities under its Subsidiary Guaranty by the Company or another Subsidiary Guarantor or (ii) such Subsidiary Guarantor being released and discharged as a co-obligor, borrower or guarantor under and in respect of the Bank Credit Agreement; provided that in the case of clause (ii) if any fee or other consideration is paid or given to any holder of Indebtedness under the Bank Credit Agreement in connection with such release, other than the repayment of all or a portion of such Indebtedness under the Bank Credit Agreement, each holder of a Note receives equivalent consideration on a pro rata basis; provided, however, that in the event the Bank Credit Agreement is amended or replaced or refinanced, and upfront fees or similar fees are paid to the lenders and/or agents or arrangers thereunder in consideration of their commitments to extend credit and/or in consideration of their agreement to provide services, such fees shall not be subject to the provisions of this subparagraph (b); and provided, further in the case of both clause (i) and (ii): (x) no Default or Event of Default exists or will exist immediately following such release and discharge; and (y) at the time of such release and discharge, the Company delivers to each holder of Notes a certificate of a Responsible Officer certifying (A) that a Disposition of such Subsidiary Guarantor has occurred in compliance with Section 10.6 or that such Subsidiary Guarantor has been or is being released and discharged as a co-obligor, borrower or guarantor under and in respect of the Bank Credit Agreement and (B) as to the matters set forth in clauses (x) and (y).

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(c) Confirmation of Release . Upon written request of the Company following release of a Guarantor pursuant to Section 9.8(b), each Holder of a Note agrees to provide written confirmation of such release.

10.

NEGATIVE COVENANTS.

The Company covenants that so long as any of the Notes are outstanding:

10.1.

Transactions with Affiliates.

The Company will not and will not permit any Subsidiary to enter into directly or indirectly any Material transaction or Material group of related transactions (including without limitation the purchase, lease, sale or exchange of properties of any kind or the rendering of any service) with any Affiliate (other than the Company or another Subsidiary), except upon fair and reasonable terms no less favorable to the Company or such Subsidiary than would be obtainable in a comparable arm’s-length transaction with a Person not an Affiliate.

10.2.

Merger, Consolidation, Etc.

The Company will not consolidate with or merge with any other Person or convey, transfer, sell or lease all or substantially all of its assets in a single transaction or series of transactions to any Person except that the Company may consolidate or merge with any other Person or convey, transfer, sell or lease all or substantially all of its assets in a single transaction or series of transactions to any Person, provided that:

(a) the successor formed by such consolidation or the survivor of such merger or the Person that acquires by conveyance, transfer, sale or lease all or substantially all of the assets of the Company as an entirety, as the case may be, is a solvent corporation, limited liability company or limited partnership organized and existing under the laws of the United States or any state thereof (including the District of Columbia), and, if the Company is not such successor or survivor, such entity (i) shall have executed and delivered, in form and substance reasonably satisfactory to the Required Holders, to each holder of any Notes its assumption of the due and punctual performance and observance of each covenant and condition of this Agreement and the Notes and (ii) shall have caused to be delivered to each holder of any Notes an opinion of nationally recognized independent counsel, or other independent counsel reasonably satisfactory to the Required Holders, to the effect that all agreements or instruments effecting such assumption are enforceable in accordance with their terms and comply with the terms of this Section 10.2(a); and

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(b) after giving effect to such transaction, no Default or Event of Default shall exist.

No such conveyance, transfer, sale or lease of all or substantially all of the assets of the Company shall have the effect of releasing the Company or any successor that shall theretofore have become such in the manner prescribed in this Section 10.2 from its liability under this Agreement or the Notes.

10.3.

Line of Business.

The Company will not and will not permit any Subsidiary to engage in any business if, as a result, the general nature of the business in which the Company and its Subsidiaries, taken as a whole, would then be engaged would be substantially changed from the general nature of the business in which the Company and its Subsidiaries, taken as a whole, are engaged on the date of this Agreement as described in the Memorandum.

10.4.

Terrorism Sanctions Regulations.

The Company will not and will not permit any Affiliated Entity to (a) become an OFAC Listed Person or (b) have any investments in, or engage in any dealings or transactions with any Blocked Person.

10.5.

Liens.

The Company will not, and will not permit any Subsidiary to, create, incur, assume or suffer to exist, directly or indirectly, any Lien on its properties or assets, including capital stock, whether now owned or hereafter acquired, except:

(a) Liens on property or assets of the Company or any Subsidiary if, at the time such Liens are created, the Notes are equally and ratably secured by a Lien on the same property and assets pursuant to an agreement or agreements (including an inter-creditor agreement) reasonably acceptable to the Required Holders;

(b) Permitted Encumbrances;

(c) Liens existing on property or assets of the Company or any Subsidiary as of the date of this Agreement that are described in Schedule 10.5;

(d) any Lien existing on any property or asset prior to the acquisition thereof by the Company or any Subsidiary or existing on any property or asset of any Person that becomes a Subsidiary after the date of this Agreement prior to the time such Person becomes a Subsidiary; provided that (i) such Lien is not created in contemplation of or in connection with such acquisition or such Person becoming a Subsidiary, as the case may be, (ii) such Lien does not apply to any other property or assets of the Company or any Subsidiary and (iii) such Lien secures only those obligations that it secures on the date of such acquisition or the date such Person becomes a Subsidiary, as the case may be, and extensions, renewals and replacements thereof that do not increase the outstanding principal amount thereof;

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(e) Liens on fixed or capital assets acquired, constructed or improved by the Company or any Subsidiary; provided that (i) such Liens and the Indebtedness secured thereby are incurred prior to or within 270 days after such acquisition or the completion of such construction or improvement, (ii) the Indebtedness secured thereby does not exceed the cost of acquiring, constructing or improving such fixed or capital assets, and (iii) such Liens do not apply to any other property or assets of the Company or any Subsidiary;

(f) Liens securing surety or other bonds required in the normal course of business;

(g) Liens on cash deposits securing obligations under Swap Agreements;

(h) any Lien renewing, extending or replacing any Lien permitted by paragraphs (c), (d) or (e) of this Section 10.5, provided that (x) the principal amount Indebtedness so secured and then outstanding is not increased, (y) the Lien is not extended to other property of the Company or such Subsidiary and (z) the Indebtedness secured thereby is permitted hereunder;

(i) Liens securing Intercompany Indebtedness;

(j) Liens securing judgments for the payment of money that individually or in the aggregate do not constitute an Event of Default under Section 11(i);

(k) Liens on the Petroleum Properties securing performance obligations under Advance Payment Contracts, provided that the aggregate outstanding amount of such obligations does not at any time exceed $10,000,000; and

(l) Liens securing Indebtedness not otherwise permitted by paragraphs (a) through (k) of this Section 10.5, provided that the outstanding principal amount of Priority Debt does not at any time exceed 10% of Consolidated Total Assets as of the end of the most recently completed fiscal quarter.

10.6.

Sale of Assets.

Except as permitted by Section 10.2, the Company will not, and will not permit any Subsidiary to, sell, lease, transfer or otherwise dispose of, including by way of merger (collectively a “ Disposition ”), any assets, in one or a series of transactions, to any Person, other than:

(a) Dispositions of surplus equipment for fair and adequate consideration;

(b) Dispositions of worthless or obsolete equipment;

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(d) Dispositions of inventory (including Hydrocarbons and seismic data) that is sold in the ordinary course of business;

(e) Dispositions not otherwise permitted by paragraphs (a), (b), (c) or (d) of this Section 10.6 provided that:

(i) in the good faith opinion of the Company, the Disposition is in exchange for consideration having a fair market value at least equal to that of the property subject to such Disposition and is in the best interest of the Company or such Subsidiary;

(ii) after giving effect to such transaction, no Default or Event of Default shall exist; and

(iii) immediately after giving effect to the Disposition, the aggregate net book value of all assets that were the subject of any Disposition pursuant to this Section 10.6(e) occurring in the then current fiscal year would not exceed 25% of Consolidated Total Assets as of the last day of the most recently ended fiscal year.

Notwithstanding the foregoing, the Company may, or may permit a Subsidiary to, make a Disposition and the assets subject to such Disposition shall not be subject to or included in the foregoing limitation and computation contained in paragraph (e)(iii) of the preceding sentence if, within 365 days of such Disposition, an amount equal to the net proceeds from such Disposition is:

(A) reinvested in productive assets to be used in the existing business of the Company or a Subsidiary (including exploration and development capital expenditures); or

(B) the net proceeds from such Disposition are applied to a Debt Prepayment Application. Solely for the purposes of the foregoing clause (B), whether or not such offers are accepted by the holders, the entire principal amount of the Notes subject to a Debt Prepayment Application shall be deemed to have been prepaid.

10.7.

Priority Debt.

The Company will not at any time permit the outstanding principal amount of Priority Debt to exceed 10% of Consolidated Total Assets as of the end of the most recently completed fiscal quarter, provided, however, that no Lien created pursuant to Section 10.5(l) shall secure Indebtedness owing under the Bank Credit Agreement unless the Notes are equally and ratably secured by all property subject to such Lien and no Subsidiary shall guaranty or otherwise become obligated in respect of such Indebtedness unless such Subsidiary guaranties, or becomes similarly obligated in respect of, the Notes pursuant to Section 9.8, in each case pursuant to documentation reasonably satisfactory to the Required Holders.

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10.8.

Asset Coverage Ratio.

(a) The ratio of (i) Present Value of Proved Reserves plus Adjusted Cash to (ii) Indebtedness and Other Liabilities shall at no time be less than 1.75:1 (the “ Asset Coverage Ratio ”); in addition, for so long as any Bank Credit Agreement is in effect and the Borrowing Base therein is being calculated, at no time shall Indebtedness and Other Liabilities exceed 115% of the Borrowing Base then in effect; provided however, that if at any time the Borrowing Base shall cease to be calculated under any Bank Credit Agreement, then (x) the ratio of (i) Indebtedness and Other Liabilities as of the end of any fiscal quarter of the Company (commencing with the fiscal quarter ended immediately preceding the date Borrowing Base is no longer being calculated) to (ii) Consolidated EBITDAX for the period of four fiscal quarters ending on such date shall not be greater than 3.00:1 and (y) the Asset Coverage Ratio shall no longer be calculated hereunder.

(i) The Present Value of Proved Reserves will be determined and adjusted periodically as follows:

(ii) The calculation of Present Value of Proved Reserves will be determined from the most recent Reserve Report.

(iii) Upon any sale by the Company or any Subsidiary of any Petroleum Property including but not limited to a sale of a lesser interest such as a royalty or a net profit interest to the extent the sale of such lesser interest is not considered to create a Lien (other than the sale of hydrocarbons after severance occurring in the ordinary course of the Company’s business), the calculation of Present Value of Proved Reserves shall be reduced, effective on the date of consummation of such sale, by an amount equal to the Present Value of Proved Reserves attributable to Proved Reserves included in such sale.

(iv) Immediately upon acquisition or development by the Company or any Subsidiary of any Petroleum Property owned directly by the Company or any Subsidiary and not reflected in the most recent Reserve Report, the calculation of Present Value of Proved Reserves shall be increased in an amount equal to the Present Value of Proved Reserves attributable to such Petroleum Property.

10.9.

Annual Coverage Ratio.

The Company will not permit as of the last day of any fiscal quarter the Annual Coverage Ratio to be less than 2.8:1. For this purpose:

(a) “ Annual Coverage Ratio ” means at any date the ratio of Consolidated Cash Flow to Consolidated Interest Expense for the period of four consecutive fiscal quarters ending on such date.

(b) “ Consolidated Cash Flow ” means, for any period, the net cash from operating activities of the Company and its Consolidated Subsidiaries for such period, as the same is, or would in accordance with GAAP be set forth in a statement of cash flows for such period, plus to the extent deducted in determining such net cash from operating activities, the sum of (x) Consolidated Interest Expense for such period and (y) income tax expense.

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(c) “ Consolidated Interest Expense ” means, for any period, the interest expense of the Company and its Consolidated Subsidiaries determined for such period in accordance with GAAP.

(d) “ Consolidated Subsidiaries ” means at any date any Subsidiary or other entity the accounts of which would in accordance with GAAP be consolidated with those of the Company in its consolidated financial statements if such statements were prepared as of such date.

11.

EVENTS OF DEFAULT.

An “Event of Default” shall exist if any of the following conditions or events shall occur and be continuing:

(a) the Company defaults in the payment of any principal or Make-Whole Amount, if any, on any Note when the same becomes due and payable, whether at maturity or at a date fixed for prepayment or by declaration or otherwise; or

(b) the Company defaults in the payment of any interest on any Note for more than five Business Days after the same becomes due and payable; or

(c) the Company defaults in the performance of or compliance with any term contained in Section 7.1(d) or Sections 10.1 through 10.9; or

(d) the Company defaults in the performance of or compliance with any term contained herein (other than those referred to in Sections 11(a), (b) and (c)) and such default is not remedied within 30 days after the earlier of (i) a Responsible Officer obtaining actual knowledge of such default and (ii) the Company receiving written notice of such default from any holder of a Note (any such written notice to be identified as a “notice of default” and to refer specifically to this Section 11(d)); or

(e) any representation or warranty made in writing by or on behalf of the Company or by any officer of the Company in this Agreement or in any writing furnished in connection with the transactions contemplated hereby proves to have been false or incorrect in any material respect on the date as of which made and if capable of being cured is not cured within 30 days; or

(f) (i) the Company or any Material Subsidiary is in default (as principal or as guarantor or other surety) in the payment of any principal of or premium or make-whole amount or interest on any Indebtedness that is outstanding in an aggregate principal amount of at least $30,000,000 beyond any period of grace provided with respect thereto, or (ii) the Company or any Material Subsidiary is in default in the performance of or compliance with any term of any evidence of any Indebtedness in an aggregate outstanding principal amount of at least $30,000,000 or of any mortgage, indenture or other agreement relating thereto or any other condition exists, and as a consequence of such default or condition such Indebtedness has become, or has been declared (or one or more Persons are entitled to declare such Indebtedness to be), due and payable before its stated maturity or before its regularly scheduled dates of payment, or (iii) as a consequence of the occurrence or continuation of any event or condition (other than the passage of time or the right of the holder of Indebtedness to convert such Indebtedness into equity interests), (x) the Company or any Material Subsidiary has become obligated to purchase or repay Indebtedness before its regular maturity or before its regularly scheduled dates of payment in an aggregate outstanding principal amount of at least $30,000,000, or (y) one or more Persons have the right to require the Company or any Subsidiary so to purchase or repay such Indebtedness; provided, that clause (iii) shall not apply to Indebtedness that becomes due (without the occurrence of any default or event of default thereunder) as a result of a disposition of assets pursuant to a due on sale or equivalent provision, issuance of equity or incurrence of other debt, provided that such Indebtedness is purchased or paid when due or within the grace period provided; or

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(g) the Company or any Material Subsidiary (i) is generally not paying, or admits in writing its inability to pay, its debts as they become due, (ii) files, or consents by answer or otherwise to the filing against it of, a petition for relief or reorganization or arrangement or any other petition in bankruptcy, for liquidation or to take advantage of any bankruptcy, insolvency, reorganization, moratorium or other similar law of any jurisdiction, (iii) makes an assignment for the benefit of its creditors, (iv) consents to the appointment of a custodian, receiver, trustee or other officer with similar powers with respect to it or with respect to any substantial part of its property, (v) is adjudicated as insolvent or to be liquidated, or (vi) takes corporate action for the purpose of any of the foregoing; or

(h) a court or Governmental Authority of competent jurisdiction enters an order appointing, without consent by the Company or any of its Material Subsidiaries, a custodian, receiver, trustee or other officer with similar powers with respect to it or with respect to any substantial part of its property, or constituting an order for relief or approving a petition for relief or reorganization or any other petition in bankruptcy or for liquidation or to take advantage of any bankruptcy or insolvency law of any jurisdiction, or ordering the dissolution, winding-up or liquidation of the Company or any of its Material Subsidiaries, or any such petition shall be filed against the Company or any of its Material Subsidiaries and such petition shall not be dismissed within 60 days; or

(i) a final judgment or judgments for the payment of money aggregating in excess of $30,000,000 are rendered against one or more of the Company and its Material Subsidiaries and which judgments are not, within 60 days after entry thereof, bonded, discharged or stayed pending appeal, or are not discharged within 60 days after the expiration of such stay;

(j) any Subsidiary Guaranty ceases to be in full force and effect (unless released in accordance with Section 9.8) or is declared to be null and void in whole or in material part by a court or other governmental or regulatory authority having jurisdiction or the validity or enforceability thereof shall be contested by the Company or any Subsidiary Guarantor or any of them renounces any of the same or denies that it has any or further liability thereunder; or

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(k) if an ERISA Event has resulted in liability of the Company or any Subsidiary under Title IV of ERISA to a Plan, a Multiemployer Plan or the PBGC in an aggregate amount in excess of $30,000,000 and such amount has not been paid when due.

12.

REMEDIES ON DEFAULT, ETC.

12.1.

Acceleration.

(a) If an Event of Default with respect to the Company described in Section 11(g) or (h) (other than an Event of Default described in clause (i) of Section 11(g) or described in clause (vi) of Section 11(g) by virtue of the fact that such clause encompasses clause (i) of Section 11(g)) has occurred, all the Notes then outstanding shall automatically become immediately due and payable.

(b) If any other Event of Default has occurred and is continuing, the Required Holders may at any time at its or their option, by notice or notices to the Company, declare all the Notes then outstanding to be immediately due and payable.

(c) If any Event of Default described in Section 11(a) or (b) has occurred and is continuing, any holder or holders of Notes at the time outstanding affected by such Event of Default may at any time, at its or their option, by notice or notices to the Company, declare all the Notes held by it or them to be immediately due and payable.

Upon any Notes becoming due and payable under this Section 12.1, whether automatically or by declaration, such Notes will forthwith mature and the entire unpaid principal amount of such Notes, plus (x) all accrued and unpaid interest thereon (including, but not limited to, interest accrued thereon at the Default Rate) and (y) the Make-Whole Amount determined in respect of such principal amount (to the full extent permitted by applicable law), shall all be immediately due and payable, in each and every case without presentment, demand, protest or further notice, all of which are hereby waived. The Company acknowledges, and the parties hereto agree, that each holder of a Note has the right to maintain its investment in the Notes free from repayment by the Company (except as herein specifically provided for) and that the provision for payment of a Make-Whole Amount by the Company in the event that the Notes are prepaid or are accelerated as a result of an Event of Default, is intended to provide compensation for the deprivation of such right under such circumstances.

12.2.

Other Remedies.

If any Default or Event of Default has occurred and is continuing, and irrespective of whether any Notes have become or have been declared immediately due and payable under Section 12.1, the holder of any Note at the time outstanding may proceed to protect and enforce the rights of such holder by an action at law, suit in equity or other appropriate proceeding, whether for the specific performance of any agreement contained herein or in any Note, or for an injunction against a violation of any of the terms hereof or thereof, or in aid of the exercise of any power granted hereby or thereby or by law or otherwise.

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12.3.

Rescission.

At any time after any Notes have been declared due and payable pursuant to Section 12(b) or (c), the Required Holders, by written notice to the Company, may rescind and annul any such declaration and its consequences if (a) the Company has paid all overdue interest on the Notes, all principal of and Make-Whole Amount, if any, on any Notes that are due and payable and are unpaid other than by reason of such declaration, and all interest on such overdue principal and Make-Whole Amount, if any, and (to the extent permitted by applicable law) any overdue interest in respect of the Notes of any Series, at the Default Rate for such Series, (b) neither the Company nor any other Person shall have paid any amounts which have become due solely by reason of such declaration, (c) all Events of Default and Defaults, other than non-payment of amounts that have become due solely by reason of such declaration, have been cured or have been waived pursuant to Section 17, and (d) no judgment or decree has been entered for the payment of any monies due pursuant hereto or to the Notes. No rescission and annulment under this Section 12.3 will extend to or affect any subsequent Event of Default or Default or impair any right consequent thereon.

12.4.

No Waivers or Election of Remedies, Expenses, Etc.

No course of dealing and no delay on the part of any holder of any Note in exercising any right, power or remedy shall operate as a waiver thereof or otherwise prejudice such holder’s rights, powers or remedies. No right, power or remedy conferred by this Agreement or by any Note upon any holder thereof shall be exclusive of any other right, power or remedy referred to herein or therein or now or hereafter available at law, in equity, by statute or otherwise. Without limiting the obligations of the Company under Section 15, the Company will pay to the holder of each Note on demand such further amount as shall be sufficient to cover all costs and expenses of such holder incurred in any enforcement or collection under this Section 12, including, without limitation, reasonable attorneys’ fees, expenses and disbursements.

13.

REGISTRATION; EXCHANGE; SUBSTITUTION OF NOTES.

13.1.

Registration of Notes.

The Company shall keep at its principal executive office a register for the registration and registration of transfers of Notes. The name and address of each holder of one or more Notes, each transfer thereof and the name and address of each transferee of one or more Notes shall be registered in such register. Prior to due presentment for registration of transfer, the Person in whose name any Note shall be registered shall be deemed and treated as the owner and holder thereof for all purposes hereof, and the Company shall not be affected by any notice or knowledge to the contrary. The Company shall give to any holder of a Note that is an Institutional Investor promptly upon request therefor, a complete and correct copy of the names and addresses of all registered holders of Notes.

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13.2.

Transfer and Exchange of Notes.

Upon surrender of any Note to the Company at the address and to the attention of the designated officer (all as specified in Section 18(iii)), for registration of transfer or exchange (and in the case of a surrender for registration of transfer accompanied by a written instrument of transfer duly executed by the registered holder of such Note or such holder’s attorney duly authorized in writing and accompanied by the relevant name, address and other information for notices of each transferee of such Note or part thereof), within ten Business Days thereafter, the Company shall execute and deliver, at the Company’s expense (except as provided below), one or more new Notes of such Series (as requested by the holder thereof) in exchange therefor, in an aggregate principal amount equal to the unpaid principal amount of the surrendered Note. Each such new Note shall be payable to such Person as such holder may request and shall be substantially in the form of such Note for such Series as set forth in Exhibit 1(a), 1(b) or 1(c), as applicable. Each such new Note shall be dated and bear interest from the date to which interest shall have been paid on the surrendered Note or dated the date of the surrendered Note if no interest shall have been paid thereon. The Company may require payment of a sum sufficient to cover any stamp tax or governmental charge imposed in respect of any such transfer of Notes. Notes shall not be transferred in denominations of less than $100,000, provided that if necessary to enable the registration of transfer by a holder of its entire holding of Notes, one Note may be in a denomination of less than $100,000. Any transferee, by its acceptance of a Note registered in its name (or the name of its nominee), shall be deemed to have made the representations set forth in Section 6.2.

13.3.

Replacement of Notes.

Upon receipt by the Company at the address and to the attention of the designated officer (all as specified in Section 18(iii)) of evidence reasonably satisfactory to it of the ownership of and the loss, theft, destruction or mutilation of any Note (which evidence shall be, in the case of an Institutional Investor, notice from such Institutional Investor of such ownership and such loss, theft, destruction or mutilation), and

(a) in the case of loss, theft or destruction, of indemnity reasonably satisfactory to it (provided that if the holder of such Note is, or is a nominee for, an original Purchaser or another holder of a Note with a minimum net worth of at least $50,000,000 or a Qualified Institutional Buyer, such Person’s own unsecured agreement of indemnity shall be deemed to be satisfactory), or

(b) in the case of mutilation, upon surrender and cancellation thereof,

within ten Business Days thereafter, the Company at its own expense shall execute and deliver, in lieu thereof, a new Note of the same Series, dated and bearing interest from the date to which interest shall have been paid on such lost, stolen, destroyed or mutilated Note or dated the date of such lost, stolen, destroyed or mutilated Note if no interest shall have been paid thereon.

14.

PAYMENTS ON NOTES.

14.1.

Place of Payment.

Subject to Section 14.2, payments of principal, Make-Whole Amount, if any, and interest becoming due and payable on the Notes shall be made in New York, New York at the principal office of JPMorgan Chase Bank, N.A. in such jurisdiction. The Company may at any time, by notice to each holder of a Note, change the place of payment of the Notes so long as such place of payment shall be either the principal office of the Company in such jurisdiction or the principal office of a bank or trust company in such jurisdiction.

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14.2.

Home Office Payment.

So long as any Purchaser or its nominee shall be the holder of any Note, and notwithstanding anything contained in Section 14.1 or in such Note to the contrary, the Company will pay all sums becoming due on such Note for principal, Make-Whole Amount, if any, and interest by the method and at the address specified for such purpose below such Purchaser’s name in Schedule A, or by such other method or at such other address as such Purchaser shall have from time to time specified to the Company in writing for such purpose, without the presentation or surrender of such Note or the making of any notation thereon, except that upon written request of the Company made concurrently with or reasonably promptly after payment or prepayment in full of any Note, such Purchaser shall surrender such Note for cancellation, reasonably promptly after any such request, to the Company at its principal executive office or at the place of payment most recently designated by the Company pursuant to Section 14.1. Prior to any sale or other disposition of any Note held by a Purchaser or its nominee, such Purchaser will, at its election, either endorse thereon the amount of principal paid thereon and the last date to which interest has been paid thereon or surrender such Note to the Company in exchange for a new Note or Notes pursuant to Section 13.2. The Company will afford the benefits of this Section 14.2 to any Institutional Investor that is the direct or indirect transferee of any Note purchased by a Purchaser under this Agreement and that has made the same agreement relating to such Note as the Purchasers have made in this Section 14.2.

15.

EXPENSES, ETC.

15.1.

Transaction Expenses.

Whether or not the transactions contemplated hereby are consummated, the Company will pay all costs and expenses (including reasonable attorneys’ fees of a special counsel and, if reasonably required by the Required Holders, local or other counsel) incurred by the Purchasers and each other holder of a Note in connection with such transactions and in connection with any amendments, waivers or consents under or in respect of this Agreement, the Notes or any Subsidiary Guaranty (whether or not such amendment, waiver or consent becomes effective), including, without limitation: (a) the costs and expenses incurred in enforcing or defending (or determining whether or how to enforce or defend) any rights under this Agreement, the Notes or any Subsidiary Guaranty or in responding to any subpoena or other legal process or informal investigative demand issued in connection with this Agreement, the Notes or any Subsidiary Guaranty, or by reason of being a holder of any Note, (b) the costs and expenses, including financial advisors’ fees, incurred in connection with the insolvency or bankruptcy of the Company or any Subsidiary or in connection with any work-out or restructuring of the transactions contemplated hereby, by the Notes and any Subsidiary Guaranty and (c) the costs and expenses incurred in connection with the initial filing of this Agreement and all related documents and financial information with the SVO provided, that such costs and expenses under this clause (c) shall not exceed $3,000. The Company will pay, and will save each Purchaser and each other holder of a Note harmless from, all claims in respect of any fees, costs or expenses, if any, of brokers and finders (other than those, if any, retained by a Purchaser or other holder in connection with its purchase of the Notes).

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15.2.

Survival.

The obligations of the Company under this Section 15 will survive the payment or transfer of any Note, the enforcement, amendment or waiver of any provision of this Agreement or the Notes, and the termination of this Agreement.

16.

SURVIVAL OF REPRESENTATIONS AND WARRANTIES; ENTIRE AGREEMENT.

All representations and warranties contained herein shall survive the execution and delivery of this Agreement and the Notes, the purchase or transfer by any Purchaser of any Note or portion thereof or interest therein and the payment of any Note, and may be relied upon by any subsequent holder of a Note, regardless of any investigation made at any time by or on behalf of such Purchaser or any other holder of a Note. All statements contained in any certificate or other instrument delivered by or on behalf of the Company pursuant to this Agreement shall be deemed representations and warranties of the Company under this Agreement. Subject to the preceding sentence, this Agreement and the Notes embody the entire agreement and understanding between each Purchaser and the Company and supersede all prior agreements and understandings relating to the subject matter hereof.

17.

AMENDMENT AND WAIVER.

17.1.

Requirements.

This Agreement, the Notes and any Subsidiary Guaranty may be amended, and the observance of any term hereof or thereof may be waived (either retroactively or prospectively), with (and only with) the written consent of the Company and the Required Holders, except that (a) no amendment or waiver of any of the provisions of Section 1, 2, 3, 4, 5, 6 or 21 hereof, or any defined term (as it is used therein), will be effective as to any Purchaser unless consented to by such Purchaser in writing, and (b) no such amendment or waiver may, without the written consent of the holder of each Note at the time outstanding affected thereby, (i) subject to the provisions of Section 12 relating to acceleration or rescission, change the amount or time of any prepayment or payment of principal of, or reduce the rate or change the time of payment or method of computation of interest or of the Make-Whole Amount on, the Notes, (ii) change the percentage of the principal amount of the Notes the holders of which are required to consent to any such amendment or waiver, or (iii) amend any of Sections 8, 11(a), 11(b), 12, 17 or 20.

17.2.

Solicitation of Holders of Notes.

(a) Solicitation . The Company will provide each holder of the Notes (irrespective of the amount of Notes then owned by it) with sufficient information, sufficiently far in advance of the date a decision is required, to enable such holder to make an informed and considered decision with respect to any proposed amendment, waiver or consent in respect of any of the provisions hereof or of the Notes. The Company will deliver executed or true and correct copies of each amendment, waiver or consent effected pursuant to the provisions of this Section 17 to each holder of outstanding Notes promptly following the date on which it is executed and delivered by, or receives the consent or approval of, the requisite holders of Notes.

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(b) Payment . The Company will not directly or indirectly pay or cause to be paid any remuneration, whether by way of supplemental or additional interest, fee or otherwise, or grant any security or provide other credit support, to any holder of Notes as consideration for or as an inducement to the entering into by any holder of Notes of any waiver or amendment of any of the terms and provisions hereof unless such remuneration is concurrently paid, or security is concurrently granted or other credit support concurrently provided, on the same terms, ratably to each holder of Notes then outstanding even if such holder did not consent to such waiver or amendment.

(c) Consent in Contemplation of Transfer . Any consent made pursuant to this Section 17.2 by the holder of any Note that has transferred or has agreed to transfer such Note to the Company, any Subsidiary or any Affiliate of the Company and has provided or has agreed to provide such written consent as a condition to such transfer shall be void and of no force or effect except solely as to such holder, and any amendments effected or waivers granted or to be effected or granted that would not have been or would not be so effected or granted but for such consent (and the consents of all other holders of Notes that were acquired under the same or similar conditions) shall be void and of no force or effect except solely as to such transferring holder.

17.3.

Binding Effect, etc.

Any amendment or waiver consented to as provided in this Section 17 applies equally to all holders of Notes and is binding upon them and upon each future holder of any Note and upon the Company without regard to whether such Note has been marked to indicate such amendment or waiver. No such amendment or waiver will extend to or affect any obligation, covenant, agreement, Default or Event of Default not expressly amended or waived or impair any right consequent thereon. No course of dealing between the Company and the holder of any Note nor any delay in exercising any rights hereunder or under any Note shall operate as a waiver of any rights of any holder of such Note. As used herein, the term “this Agreement” and references thereto shall mean this Agreement as it may from time to time be amended or supplemented.

17.4.

Notes Held by Company, etc.

Solely for the purpose of determining whether the holders of the requisite percentage of the aggregate principal amount of Notes then outstanding approved or consented to any amendment, waiver or consent to be given under this Agreement or the Notes, or have directed the taking of any action provided herein or in the Notes to be taken upon the direction of the holders of a specified percentage of the aggregate principal amount of Notes then outstanding, Notes directly or indirectly owned by the Company or any of its Affiliates shall be deemed not to be outstanding.

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18.

NOTICES.

All notices and communications provided for hereunder shall be in writing and sent (a) by telecopy if the sender on the same day sends a confirming copy of such notice by a recognized overnight delivery service (charges prepaid), or (b) by registered or certified mail with return receipt requested (postage prepaid), or (c) by a recognized overnight delivery service (with charges prepaid). Any such notice must be sent:

(i) if to any Purchaser or its nominee, to such Purchaser or nominee at the address specified for such communications in Schedule A, or at such other address as such Purchaser or nominee shall have specified to the Company in writing,

(ii) if to any other holder of any Note, to such holder at such address as such other holder shall have specified to the Company in writing, or

(iii) if to the Company, to the Company at its address set forth at the beginning hereof to the attention of Scott C. Schroeder, Vice President, or at such other address as the Company shall have specified to the holder of each Note in writing.

Notices under this Section 18 will be deemed given only when actually received.

19.

REPRODUCTION OF DOCUMENTS.

This Agreement and all documents relating thereto, including, without limitation, (a) consents, waivers and modifications that may hereafter be executed, (b) documents received by any Purchaser at the Closing (except the Notes themselves), and (c) financial statements, certificates and other information previously or hereafter furnished to any Purchaser, may be reproduced by such Purchaser by any photographic, photostatic, electronic, digital, or other similar process and such Purchaser may destroy any original document so reproduced. The Company agrees and stipulates that, to the extent permitted by applicable law, any such reproduction shall be admissible in evidence as the original itself in any judicial or administrative proceeding (whether or not the original is in existence and whether or not such reproduction was made by such Purchaser in the regular course of business) and any enlargement, facsimile or further reproduction of such reproduction shall likewise be admissible in evidence. This Section 19 shall not prohibit the Company or any other holder of Notes from contesting any such reproduction to the same extent that it could contest the original, or from introducing evidence to demonstrate the inaccuracy of any such reproduction.

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20.

CONFIDENTIAL INFORMATION.

For the purposes of this Section 20, “Confidential Information” means information delivered to any Purchaser by or on behalf of the Company or any Subsidiary in connection with the transactions contemplated by or otherwise pursuant to this Agreement that is proprietary in nature and that was clearly marked or labeled or otherwise adequately identified when received by such Purchaser as being confidential information of the Company or such Subsidiary, provided that such term does not include information that (a) was publicly known or otherwise known to such Purchaser prior to the time of such disclosure, (b) subsequently becomes publicly known through no act or omission by such Purchaser or any person acting on such Purchaser’s behalf, (c) otherwise becomes known to such Purchaser other than through disclosure by the Company or any Subsidiary or (d) constitutes financial statements delivered to such Purchaser under Section 7.1 that are otherwise publicly available. Each Purchaser will maintain the confidentiality of such Confidential Information in accordance with procedures adopted by such Purchaser in good faith to protect confidential information of third parties delivered to such Purchaser, provided that such Purchaser may deliver or disclose Confidential Information to (i) its directors, officers, employees, agents, attorneys, trustees and affiliates (to the extent such disclosure reasonably relates to the administration of the investment represented by its Notes), (ii) its financial advisors and other professional advisors who agree to hold confidential the Confidential Information substantially in accordance with the terms of this Section 20, (iii) any other holder of any Note, (iv) any Institutional Investor to which it sells or offers to sell such Note or any part thereof or any participation therein (if such Person has agreed in writing prior to its receipt of such Confidential Information to be bound by the provisions of this Section 20), (v) any Person from which it offers to purchase any security of the Company (if such Person has agreed in writing prior to its receipt of such Confidential Information to be bound by the provisions of this Section 20), (vi) any federal, state or provincial regulatory authority having jurisdiction over such Purchaser, (vii) the NAIC or the SVO or, in each case, any similar organization, or any nationally recognized rating agency that requires access to information about such Purchaser’s investment portfolio, or (viii) any other Person to which such delivery or disclosure may be necessary or appropriate (w) to effect compliance with any law, rule, regulation or order applicable to such Purchaser, (x) in response to any subpoena or other legal process, (y) in connection with any litigation to which such Purchaser is a party or (z) if an Event of Default has occurred and is continuing, to the extent such Purchaser may reasonably determine such delivery and disclosure to be necessary or appropriate in the enforcement or for the protection of the rights and remedies under such Purchaser’s Notes and this Agreement. Each holder of a Note, by its acceptance of a Note, will be deemed to have agreed to be bound by and to be entitled to the benefits of this Section 20 as though it were a party to this Agreement. On reasonable request by the Company in connection with the delivery to any holder of a Note of information required to be delivered to such holder under this Agreement or requested by such holder (other than a holder that is a party to this Agreement or its nominee), such holder will enter into an agreement with the Company embodying the provisions of this Section 20.

21.

SUBSTITUTION OF PURCHASER.

Each Purchaser shall have the right to substitute any one of its Affiliates as the purchaser of the Notes that it has agreed to purchase hereunder, by written notice to the Company, which notice shall be signed by both such Purchaser and such Affiliate, shall contain such Affiliate’s agreement to be bound by this Agreement and shall contain a confirmation by such Affiliate of the accuracy with respect to it of the representations set forth in Section 6. Upon receipt of such notice, any reference to such Purchaser in this Agreement (other than in this Section 21), shall be deemed to refer to such Affiliate in lieu of such original Purchaser. In the event that such Affiliate is so substituted as a Purchaser hereunder and such Affiliate thereafter transfers to such original Purchaser all of the Notes then held by such Affiliate, upon receipt by the Company of notice of such transfer, any reference to such Affiliate as a “Purchaser” in this Agreement (other than in this Section 21), shall no longer be deemed to refer to such Affiliate, but shall refer to such original Purchaser, and such original Purchaser shall again have all the rights of an original holder of the Notes under this Agreement.

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22.

MISCELLANEOUS.

22.1.

Successors and Assigns.

All covenants and other agreements contained in this Agreement by or on behalf of any of the parties hereto bind and inure to the benefit of their respective successors and assigns (including, without limitation, any subsequent holder of a Note) whether so expressed or not.

22.2.

Payments Due on Non-Business Days.

Anything in this Agreement or the Notes to the contrary notwithstanding (but without limiting the requirement in Section 8.6 that the notice of any optional prepayment specify a Business Day as the date fixed for such prepayment), any payment of principal of or Make-Whole Amount or interest on any Note that is due on a date other than a Business Day shall be made on the next succeeding Business Day without including the additional days elapsed in the computation of the interest payable on such next succeeding Business Day; provided that if the maturity date of any Note is a date other than a Business Day, the payment otherwise due on such maturity date shall be made on the next succeeding Business Day and shall include the additional days elapsed in the computation of interest payable on such next succeeding Business Day.

22.3.

Accounting Terms.

All accounting terms used herein which are not expressly defined in this Agreement have the meanings respectively given to them in accordance with GAAP. Except as otherwise specifically provided herein, (i) all computations made pursuant to this Agreement shall be made in accordance with GAAP, and (ii) all financial statements shall be prepared in accordance with GAAP. Notwithstanding the foregoing or any other provision of this Agreement, for purposes of determining compliance with the financial covenants contained in this Agreement, any election by the Company to measure any portion of a non-derivative financial liability at fair value (as permitted by Financial Accounting Standards Board Accounting Standards Codification Section 825-10 or any similar accounting standard), other than to reflect a hedge of such non-derivative financial liability (including both interest rate and foreign currency hedges), shall be disregarded and such determination shall be made as if such election had not been made.

22.4.

Severability.

Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall (to the full extent permitted by law) not invalidate or render unenforceable such provision in any other jurisdiction.

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22.5.

Construction, etc.

Each covenant contained herein shall be construed (absent express provision to the contrary) as being independent of each other covenant contained herein, so that compliance with any one covenant shall not (absent such an express contrary provision) be deemed to excuse compliance with any other covenant. Where any provision herein refers to action to be taken by any Person, or which such Person is prohibited from taking, such provision shall be applicable whether such action is taken directly or indirectly by such Person.

For the avoidance of doubt, all Schedules and Exhibits attached to this Agreement shall be deemed to be a part hereof.

22.6.

Counterparts.

This Agreement may be executed in any number of counterparts, each of which shall be an original but all of which together shall constitute one instrument. Each counterpart may consist of a number of copies hereof, each signed by less than all, but together signed by all, of the parties hereto.

22.7.

Governing Law.

This Agreement shall be construed and enforced in accordance with, and the rights of the parties shall be governed by, the law of the State of New York excluding choice-of-law principles of the law of such State that would permit the application of the laws of a jurisdiction other than such State.

22.8.

Jurisdiction and Process; Waiver of Jury Trial.

(a) The Company irrevocably submits to the non-exclusive jurisdiction of any New York State or federal court sitting in the Borough of Manhattan, The City of New York, over any suit, action or proceeding arising out of or relating to this Agreement, the Notes or any Subsidiary Guaranty. To the fullest extent permitted by applicable law, the Company irrevocably waives and agrees not to assert, by way of motion, as a defense or otherwise, any claim that it is not subject to the jurisdiction of any such court, any objection that it may now or hereafter have to the laying of the venue of any such suit, action or proceeding brought in any such court and any claim that any such suit, action or proceeding brought in any such court has been brought in an inconvenient forum.

(b) The Company consents to process being served by or on behalf of any holder of Notes in any suit, action or proceeding of the nature referred to in Section 22.8(a) by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, return receipt requested, to it at its address specified in Section 18 or at such other address of which such holder shall then have been notified pursuant to said Section. The Company agrees that such service upon receipt (i) shall be deemed in every respect effective service of process upon it in any such suit, action or proceeding and (ii) shall, to the fullest extent permitted by applicable law, be taken and held to be valid personal service upon and personal delivery to it. Notices hereunder shall be conclusively presumed received as evidenced by a delivery receipt furnished by the United States Postal Service or any reputable commercial delivery service.

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(c) Nothing in this Section 22.8 shall affect the right of any holder of a Note to serve process in any manner permitted by law, or limit any right that the holders of any of the Notes may have to bring proceedings against the Company in the courts of any appropriate jurisdiction or to enforce in any lawful manner a judgment obtained in one jurisdiction in any other jurisdiction.

(d) The parties hereto hereby waive trial by jury in any action brought on or with respect to this Agreement, the Notes or any other document executed in connection herewith or therewith.

[Remainder of page left intentionally blank. Next page is signature page.]

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If you are in agreement with the foregoing, please sign the form of agreement on a counterpart of this Agreement and return it to the Company, whereupon this Agreement shall become a binding agreement between you and the Company.


Very truly yours,
CABOT OIL & GAS CORPORATION

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

This Agreement is hereby

accepted and agreed to as

of the date thereof.

[Signature Page to Note Purchase Agreement]


This Agreement is hereby accepted and agreed to as of the date thereof.

THE PRUDENTIAL INSURANCE COMPANY OF AMERICA

By:	/s/ Brian N. Thomas
Name:	Brian N. Thomas
Title:	Vice President

FORETHOUGHT LIFE INSURANCE COMPANY

By:	Prudential Private Placement Investors, L.P. (as Investment Advisor)

By:	Prudential Private Placement Investors, Inc. (as its General Partner)

	By:	/s/ Brian N. Thomas
	Name:	Brian N. Thomas
	Title:	Vice President

BCBSM, INC. DBA BLUE CROSS AND BLUE SHIELD OF MINNESOTA

By:	Prudential Private Placement Investors, L.P. (as Investment Advisor)

By:	Prudential Private Placement Investors, Inc. (as its General Partner)

	By:	/s/ Brian N. Thomas
	Name:	Brian N. Thomas
	Title:	Vice President

[Signature Page to Note Purchase Agreement - Cabot Oil & Gas Corporation]


THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
By:	Delaware Investment Advisers, a series of Delaware Management Business Trust, Attorney in Fact

	By:	/s/ Nicole W. Tullo
	Name:	Nicole W. Tullo
	Title:	Vice President

[Signature Page to Note Purchase Agreement - Cabot Oil & Gas Corporation]


JOHN HANCOCK LIFE INSURANCE COMPANY (U.S.A)

By:		/s/ Adam Wise
Name:		Adam Wise
Title:		Director

JOHN HANCOCK LIFE INSURANCE COMPANY OF NEW YORK

By:		/s/ Adam Wise
Name:		Adam Wise
Title:		Authorized Signatory

[Signature Page to Note Purchase Agreement - Cabot Oil & Gas Corporation]


JPMORGAN CHASE BANK, not individually but solely in its capacity as Directed Trustee for the SBC Master Pension Trust

By:		/s/ Barry O’Conner
Name:		Barry O’Conner
Title:		Executive Director


CUNA MUTUAL INSURANCE SOCIETY CUMIS INSURANCE SOCIETY, INC.
By:	MEMBERS Capital Advisors, Inc., acting as Investment Advisor

	By:	/s/ Allen R. Cantrell
	Name:	Allen R. Cantrell
	Title:	Managing Director, Investments

[Signature Page to Note Purchase Agreement – Cabot Oil & Gas Corporation]


COLONIAL LIFE & ACCIDENT INSURANCE COMPANY
By:	Provident Investment Management, LLC
Its:	Agent

	By:	/s/ Ben Vance
	Name:	Ben Vance
	Title:	Managing Director

[Signature Page to Note Purchase Agreement – Cabot Oil & Gas Corporation]


CONNECTICUT GENERAL LIFE INSURANCE COMPANY
By:	CIGNA Investments, Inc. (authorized agent)


	By:	/s/ Lori E. Hopkins
	Name:
	Tile:


LIFE INSURANCE COMPANY OF NORTH AMERICA
By:	CIGNA Investments, Inc. (authorized agent)


	By:	/s/ Lori E. Hopkins
	Name:
	Tile:

[Signature Page to Note Purchase Agreement – Cabot Oil & Gas Corporation]


THE OHIO NATIONAL LIFE INSURANCE COMPANY

By:		/s/ Jed R. Martin
Name:		Jed R. Martin
Title:		Vice President, Private Placements


OHIO NATIONAL LIFE ASSURANCE CORPORATION

By:		/s/ Jed R. Martin
Name:		Jed R. Martin
Title:		Vice President, Private Placements

[Signature Page to Note Purchase Agreement – Cabot Oil & Gas Corporation]


NATIONAL GUARDIAN LIFE INSURANCE COMPANY

By:		/s/ Robert A. Mucci
Name:		Robert A. Mucci
Title:		Senior Vice President & Treasurer


SETTLERS LIFE INSURANCE COMPANY

By:		/s/ Robert A. Mucci
Name:		Robert A. Mucci
Title:		Vice President & Treasurer

[Signature Page to Note Purchase Agreement – Cabot Oil & Gas Corporation]

SCHEDULE A

INFORMATION RELATING TO PURCHASERS


Purchaser Name	THE PRUDENTIAL INSURANCE COMPANY OF AMERICA
Name in Which to Register Note(s)	THE PRUDENTIAL INSURANCE COMPANY OF AMERICA
Note Registration Number(s); Principal Amount(s)	RH-1; $25,000,000 RI-1; $18,500,000 RJ-1; $25,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer JPMorgan Chase Bank New York, NY ABA No.: 021-000-021 Account Name: Prudential Managed Portfolio Account No.: P86188 (do not include spaces) Each such wire transfer shall reference Security No. INV11061 and the “Accompanying Information” below.
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION

	Description of Security:	5.42% Series H Senior Notes due January 15, 2021

	PPN:	127097 D*1

	Description of Security:	5.59% Series I Senior Notes due January 15, 2023

	PPN:	127097 D@9

	Description of Security:	5.80% Series J Senior Notes due January 15, 2026

	PPN:	127097 D#7

	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.

Schedule A-1


Purchaser Name	THE PRUDENTIAL INSURANCE COMPANY OF AMERICA
Address / Fax # for notices related to payments	The Prudential Insurance Company of America c/o Investment Operations Group Gateway Center Two, 10th Floor 100 Mulberry Street Newark, NJ 07102-4077 Attn: Manager, Billings and Collections with telephonic prepayment notices to: Manager, Trade Management Group
	Tel:	973-367-3141
	Fax:	888-889-3832
Address / Fax # for all other notices	The Prudential Insurance Company of America c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attn: Managing Director, Energy and Corporate Finance
Instructions re Delivery of Notes	Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention: William H. Bulmer
Signature Block	THE PRUDENTIAL INSURANCE COMPANY OF AMERICA
	By:
	Name:
	Title: Vice President
Tax identification number	22-1211670

Schedule A-2


Purchaser Name	FORETHOUGHT LIFE INSURANCE COMPANY
Name in Which to Register Note(s)	FORETHOUGHT LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RI-2; $5,000,000
Payment on Account of Note(s) Method Account Information	Federal Funds Wire Transfer State Street Bank ABA # 011000028 DDA # 24564783 For Further Credit: Forethought Life Insurance Company Fund # 3N1H Ref: “Accompanying Information” below.
Accompanying Information	Name of Issuer:	CABOT OIL & GAS CORPORATION

	Description of Security:	5.59% Series I Senior Notes due January 15, 2023

	PPN:	127097 D@9

	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address/Fax for Notices Related to Payments	Forethought Life Insurance Company Attn: Russell L. Jackson 300 North Meridian, Suite 1800 Indianapolis, IN 46204 Phone: 317-223-2749 Email: russell.jackson@forethought.com with copy to: State Street Bank Attn: Deb Hartner 801 Pennsylvania Kansas City, MO 64105 Phone: 816-871-9218 Email: DSHartner@statestreet.com
Address/Fax for All Other Notices	Prudential Private Placement Investors, L.P. c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention: Managing Director, Energy and Corporate Finance

Schedule A-3


Purchaser Name	FORETHOUGHT LIFE INSURANCE COMPANY
Instructions re: Delivery of Notes	DTC / New York Window 55 Water Street New York, NY 10041 Attention: Robert Mendez Ref: SSB Fund # 3N1H With a copy to: Prudential Capital Group Gateway Center 4 100 Mulberry, 7th Floor Newark, NJ 07102 Attention: Trade Management, Manager Telephone: (973) 367-3141 and Forethought Life Insurance Company Attn: Eric Todd 300 North Meridian Suite 1800 Indianapolis, IN 46204
Signature Block	FORETHOUGHT LIFE INSURANCE COMPANY
	By:	Prudential Private Placement Investors, L.P. (as Investment Advisor)
	By:	Prudential Private Placement Investors, Inc. (as its General Partner)
	By:
	Name:
	Title:	Vice President
Tax Identification Number	06-1016329

Schedule A-4


Purchaser Name	BCBSM, INC. DBA BLUE CROSS AND BLUE SHIELD OF MINNESOTA
Name in Which to Register Note(s)	BLUE CROSS AND BLUE SHIELD OF MINNESOTA
Note Registration Number(s); Principal Amount(s)	RI-3; $1,500,000
Payment on Account of Note(s) Method Account Information	Federal Funds Wire Transfer U.S. Bank N.A. ABA No.: 091000022 Account No. 180183083765 60 Livingston Avenue St. Paul, MN 55107 Attn: Income Team (PPN Number, Account No. 10561811 and payment breakdown) Ref: “Accompanying Information” below
Accompanying Information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.59% Series I Senior Notes due January 15, 2023
	PPN:	127097 D@9
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address/Fax for Notices Related to Payments	Blue Cross and Blue Shield of Minnesota 1303 Corporate Center Drive Eagan, MN 55121-1204 Attention: James K. Rochat, Director, Investments Telephone: (651) 662-8372 Facsimile: (651) 662-2164
Address/Fax for All Other Notices	Prudential Private Placement Investors, L.P. c/o Prudential Capital Group 2200 Ross Avenue, Suite 4200E Dallas, TX 75201 Attention: Managing Director, Energy and Corporate Finance
Instructions re: Delivery of Notes	U.S. Bank Cindy Procai EP MN WS41 60 Livingston Ave. St. Paul, MN 55107 Attention: Kate O’Connor Telephone: (651) 495-4175 Re: Blue Cross & Blue Shield of Minnesota; Account Number: 10561811 With a copy to: Prudential Capital Group Gateway Center 4 100 Mulberry, 7th Floor Newark, NJ 07102 Attention: Trade Management, Manager Telephone: (973) 367-3141

Schedule A-5


Purchaser Name	BCBSM, INC. DBA BLUE CROSS AND BLUE SHIELD OF MINNESOTA
Signature Block	BCBSM, INC. DBA BLUE CROSS AND BLUE SHIELD OF MINNESOTA
	By:	Prudential Private Placement Investors, L.P. (as Investment Advisor)
	By:	Prudential Private Placement Investors, Inc. (as its General Partner)
	By:
	Name:
	Title:	Vice President
Tax Identification Number	41-0984460

Schedule A-6


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RH-2; $11,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer The Bank of New York Mellon New York, NY ABA #: 021000018 BFN Account #: IOC566 Attn: Private Placement P&I Dept For Further Credit to the Account of: The Lincoln National Life Insurance Company For Further Credit Account #: 215715 Ref: “Accompanying information” below
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	The Bank of New York Mellon P.O. Box 19266 Newark, NJ 07195 Attn: Private Placement P&I Department Reference: The Lincoln National Life Insurance Company – Seg LNL11 and PPN and Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements) and Lincoln Financial Group 1300 South Clinton Street, Mail Stop 2H-17 Fort Wayne, IN 46802 Attn: K. Estep – Investment Accounting Fax: 260-455-2622 (Investment Accounting)

Schedule A-7


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Address / Fax # for all other notices	Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements)
Instructions re Delivery of Notes	The Bank of New York Mellon One Wall Street, 3 ^rd Floor New York, NY 10286 Attn: Arnold Musella - Free Receive Department (212-635-1917) Ref: The Lincoln National Life Insurance Company – Seg LNL11, Account #215715 Cc: Kathy Bireley
Signature Block	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
	By:	Delaware Investment Advisers, a series of Delaware Management Business Trust, Attorney in Fact
		By:
		Name:
		Title:
Tax identification number	35-0472300

Schedule A-8


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RH-3; $10,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer The Bank of New York Mellon New York, NY ABA #: 021000018 BFN Account #: IOC566 Attn: Private Placement P&I Dept For Further Credit to the Account of: The Lincoln National Life Insurance Company For Further Credit Account #: 215733 Ref: “Accompanying information” below
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	The Bank of New York Mellon P.O. Box 19266 Newark, NJ 07195 Attn: Private Placement P&I Department Reference: The Lincoln National Life Insurance Company – Seg LNL66 and PPN and Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements) and Lincoln Financial Group 1300 South Clinton Street, Mail Stop 2H-17 Fort Wayne, IN 46802 Attn: K. Estep – Investment Accounting Fax: 260-455-2622 (Investment Accounting)

Schedule A-9


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Address / Fax # for all other notices	Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements)
Instructions re Delivery of Notes	The Bank of New York Mellon One Wall Street, 3 ^rd Floor New York, NY 10286 Attn: Arnold Musella - Free Receive Department (212-635-1917) Ref: The Lincoln National Life Insurance Company – Seg LNL66, Account #215733 Cc: Kathy Bireley
Signature Block	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY

	By:	Delaware Investment Advisers, a series of Delaware Management Business Trust, Attorney in Fact
		By:
		Name:
		Title:
Tax identification number	35-0472300

Schedule A-10


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RH-4; $8,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer The Bank of New York Mellon New York, NY ABA #: 021000018 BFN Account #: IOC566 Attn: Private Placement P&I Dept For Further Credit to the Account of: The Lincoln National Life Insurance Company For Further Credit Account #: 215710 Ref: “Accompanying information” below
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	The Bank of New York Mellon P.O. Box 19266 Newark, NJ 07195 Attn: Private Placement P&I Department Reference: The Lincoln National Life Insurance Company – Seg LNL01 and PPN and Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements) and Lincoln Financial Group 1300 South Clinton Street, Mail Stop 2H-17 Fort Wayne, IN 46802 Attn: K. Estep – Investment Accounting Fax: 260-455-2622 (Investment Accounting)

Schedule A-11


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Address / Fax # for all other notices	Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements)
Instructions re Delivery of Notes	The Bank of New York Mellon One Wall Street, 3 ^rd Floor New York, NY 10286 Attn: Arnold Musella - Free Receive Department (212-635-1917) Ref: The Lincoln National Life Insurance Company – Seg LNL01, Account #215710 Cc: Kathy Bireley
Signature Block	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
	By:	Delaware Investment Advisers, a series of Delaware Management Business Trust, Attorney in Fact
		By:
		Name:
		Title:
Tax identification number	35-0472300

Schedule A-12


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RH-5; $5,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer The Bank of New York Mellon New York, NY ABA #: 021000018 BFN Account #: IOC566 Attn: Private Placement P&I Dept For Further Credit to the Account of: The Lincoln National Life Insurance Company For Further Credit Account #: 215736 Ref: (See “Accompanying information” below)
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	The Bank of New York Mellon P.O. Box 19266 Newark, NJ 07195 Attn: Private Placement P&I Department Reference: The Lincoln National Life Insurance Company – Seg LNL76 and PPN and Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements) and Lincoln Financial Group 1300 South Clinton Street, Mail Stop 2H-17 Fort Wayne, IN 46802 Attn: K. Estep – Investment Accounting Fax: 260-455-2622 (Investment Accounting)

Schedule A-13


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Address / Fax # for all other notices	Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements)
Instructions re Delivery of Notes	The Bank of New York Mellon One Wall Street, 3 ^rd Floor New York, NY 10286 Attn: Arnold Musella - Free Receive Department (212-635-1917) Ref: The Lincoln National Life Insurance Company – Seg LNL76, Account #215736 Cc: Kathy Bireley
Signature Block	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
	By:	Delaware Investment Advisers, a series of Delaware Management Business Trust, Attorney in Fact
		By:
		Name:
		Title:
Tax identification number	35-0472300

Schedule A-14


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RH-6; $3,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer The Bank of New York Mellon New York, NY ABA #: 021000018 BFN Account #: IOC566 Attn: Private Placement P&I Dept For Further Credit to the Account of: The Lincoln National Life Insurance Company For Further Credit Account #: 186228 Ref: (See “Accompanying information” below)
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	The Bank of New York Mellon P.O. Box 19266 Newark, NJ 07195 Attn: Private Placement P&I Department Reference: The Lincoln National Life Insurance Company – Seg JP201 and PPN and Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements) and Lincoln Financial Group 1300 South Clinton Street, Mail Stop 2H-17 Fort Wayne, IN 46802 Attn: K. Estep – Investment Accounting Fax: 260-455-2622 (Investment Accounting)

Schedule A-15


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Address / Fax # for all other notices	Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements)
Instructions re Delivery of Notes	The Bank of New York Mellon One Wall Street, 3 ^rd Floor New York, NY 10286 Attn: Arnold Musella - Free Receive Department (212-635-1917) Ref: The Lincoln National Life Insurance Company – Seg JP201, Account #186228 Cc: Kathy Bireley
Signature Block	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
	By:	Delaware Investment Advisers, a series of Delaware Management Business Trust, Attorney in Fact
		By:
		Name:
		Title:
Tax identification number	35-0472300

Schedule A-16


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RH-7; $3,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer The Bank of New York Mellon New York, NY ABA #: 021000018 BFN Account #: IOC566 Attn: Private Placement P&I Dept For Further Credit to the Account of: The Lincoln National Life Insurance Company For Further Credit Account #: 215726 Ref: (See “Accompanying information” below)
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION

	Description of Security:	5.42% Series H Senior Notes due January 15, 2021

	PPN:	127097 D*1

	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	The Bank of New York Mellon P.O. Box 19266 Newark, NJ 07195 Attn: Private Placement P&I Department Reference: The Lincoln National Life Insurance Company – Seg LNL46 and PPN and Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements) and Lincoln Financial Group 1300 South Clinton Street, Mail Stop 2H-17 Fort Wayne, IN 46802 Attn: K. Estep – Investment Accounting Fax: 260-455-2622 (Investment Accounting)

Schedule A-17


Purchaser Name	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
Address / Fax # for all other notices	Delaware Investment Advisers 2005 Market Street, Mail Stop 41-104 Philadelphia, PA 19103 Attn: Fixed Income Private Placements Fax: 215-255-1654 (Private Placements)
Instructions re Delivery of Notes	The Bank of New York Mellon One Wall Street, 3 ^rd Floor New York, NY 10286 Attn: Arnold Musella - Free Receive Department (212-635-1917) Ref: The Lincoln National Life Insurance Company – Seg LNL46, Account #215726 Cc: Kathy Bireley
Signature Block	THE LINCOLN NATIONAL LIFE INSURANCE COMPANY
	By:	Delaware Investment Advisers, a series of Delaware Management Business Trust, Attorney in Fact

		By:
		Name:
		Title:
Tax identification number	35-0472300

Schedule A-18


Purchaser Name	JOHN HANCOCK LIFE INSURANCE COMPANY (U.S.A.)
Note Registration Number(s); Principal Amount(s)	JOHN HANCOCK LIFE INSURANCE COMPANY (U.S.A.)
Note Registration Number(s); Principal Amount(s)	RJ-2; $19,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer Bank Name: ABA Number: Account Number: Account Name: For Further Credit to:	Bank of New York Mellon 011001234 JPPF1001002 US PP Collector F008 DDA Number 048771
	On Order of: “Accompanying information” below
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.80% Series J Senior Notes due January 15, 2026
	PPN:	127097 D#7
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: US Securities Operations, C-4 Fax: (617) 572-0628 and John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: Investment Administration, C-2 Fax: (617) 572-5495
Address / Fax # for all other notices	John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: Investment Law, C-3 Fax: (617) 572-9269 And (including copies of notices regarding compliance reporting, financial statements and related certifications) to: John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: Bond and Corporate Finance, C-2 Fax: (617) 572-5068

Schedule A-19


Purchaser Name		JOHN HANCOCK LIFE INSURANCE COMPANY (U.S.A.)
Instructions re Delivery of Notes		John Hancock Life Insurance Company 197 Clarendon St., C-3 Boston, MA 02116 Attn: Pam Memishian, Esq.
Signature Block		JOHN HANCOCK LIFE INSURANCE COMPANY (U.S.A.)
		By:
		Name:
		Title:
Tax identification number		01-0233346

Schedule A-20


Purchaser Name	JOHN HANCOCK LIFE INSURANCE COMPANY OF NEW YORK
Note Registration Number(s); Principal Amount(s)	JOHN HANCOCK LIFE INSURANCE COMPANY OF NEW YORK
Note Registration Number(s); Principal Amount(s)	RJ-3; $4,000,000 RJ-4; $3,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer
	Bank Name:	Bank of New York Mellon
	ABA Number:	011001234
	Account Number:	JPPF1001002
	Account Name:	US PP Collector F008
	For Further Credit to:	DDA Number: 048771
	On Order of: “Accompanying information” below
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.80% Series J Senior Notes due January 15, 2026
	PPN:	127097 D#7
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: US Securities Operations, C-4 Fax: (617) 572-0628 and John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: Investment Administration, C-2 Fax: (617) 572-5495
Address / Fax # for all other notices	John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: Investment Law, C-3 Fax: (617) 572-9269 And (including copies of notices regarding compliance reporting, financial statements and related certifications) to: John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: Bond and Corporate Finance, C-2 Fax: (617) 572-5068

Schedule A-21


Purchaser Name		JOHN HANCOCK LIFE INSURANCE COMPANY OF NEW YORK
Instructions re Delivery of Notes		John Hancock Life Insurance Company 197 Clarendon St., C-3 Boston, MA 02116 Attn: Pam Memishian, Esq.
Signature Block		JOHN HANCOCK LIFE INSURANCE COMPANY OF NEW YORK
		By:
		Name:
		Title:
Tax identification number		13-3646501

Schedule A-22


Purchaser Name	JPMORGAN CHASE BANK, AS DIRECTED TRUSTEE FOR THE SBC MASTER PENSION TRUST
Note Registration Number(s); Principal Amount(s)	KANE & CO.
Note Registration Number(s); Principal Amount(s)	RJ-5; $1,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer
	For Principal and Interests Payments:
	Bank Name:	JPMorgan Chase Bank
	ABA Number:	021000021
	Account Name:	ATTIMCO – John Hancock Private Placement – P58512
	Account Number:	9009000200
	Reference:	Income Details
	On Order of: “Accompanying information” below For All Other Payments:
	Bank Name:	JPMorgan Chase Bank
	ABA Number:	021000021
	Account Name:	ATTIMCO – John Hancock Private Placement – P58512
	Account Number:	9009000127
	Reference:	Income Details
	On Order of: “Accompanying information” below
Accompanying information	Name of Issuer: CABOT OIL & GAS CORPORATION
	Description of Security:	5.80% Series J Senior Notes due January 15, 2026
	PPN:	127097 D#7
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	JPMorgan Chase Bank 3 MetroTech Center, 5 ^th Floor Brooklyn, NY 11245 Attn: Robert M. Lauer Fax: (718) 242-2319

Schedule A-23


Purchaser Name		JPMORGAN CHASE BANK, AS DIRECTED TRUSTEE FOR THE SBC MASTER PENSION TRUST
Address / Fax # for all other notices		John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: Investment Law, C-3 Fax: (617) 572-9269 And (including copies of notices regarding compliance reporting, financial statements and related certifications) to: John Hancock Financial Services 197 Clarendon Street Boston, MA 02116 Attn: Bond and Corporate Finance, C-2 Fax: (617) 572-5068
Instructions re Delivery of Notes		JPMorgan Chase Bank 4 New York Plaza, Ground Floor New York, NY 10004 Ref: John Hancock Private Placement P58512
Signature Block		JPMORGAN CHASE BANK, NOT INDIVIDUALLY BUT SOLELY IN ITS CAPACITY AS DIRECTED TRUSTEE FOR THE SBC MASTER PENSION TRUST
		By:
		Name:
		Title:
Tax identification number		91-1990052

Schedule A-24


Purchaser Name	CUNA MUTUAL INSURANCE SOCIETY
Note Registration Number(s); Principal Amount(s)	TURNKEYS + CO
Note Registration Number(s); Principal Amount(s)	RH-8; $12,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer State Street Bank ABA #11000028 Account Name: CUNA Mutual Insurance Society DDA#: 1044-851-2 Reference Fund #ZT1E, Nominee Name Turnkeys + CO Re: (See “Accompanying information” below)
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	Email: DS-PRIVATEPLACEMENTS@CUNAMUTUAL.COM CUNA Mutual Insurance Society c/o MEMBERS Capital Advisors, Inc. 5910 Mineral Point Road Madison, WI 53705-4456 Attn: Carrie Snell (carrie.snell@cunamutual.com) Fax 608-231-8639
Address / Fax # for all other notices	Email: DS-PRIVATEPLACEMENTS@CUNAMUTUAL.COM CUNA Mutual Insurance Society c/o MEMBERS Capital Advisors, Inc. 5910 Mineral Point Road Madison, WI 53705-4456
	Attn: Allen Cantrell (Al.Cantrell@cunamutual.com) John Britt (john.britt@cunamutual.com) Carrie Snell (carrie.snell@cunamutual.com) Fax: 608-236-8228 (Allen Cantrell) 860-693-6402 (John Britt) 608-231-8639 (Carrie Snell)
Instructions re Delivery of Notes	State Street Bank DTC/New York Window 55 Water Street Plaza Level – 3 ^rd Floor New York, NY 10041 Attn: Robert Mendez Ref: ZT1E / Turnkeys + CO

Schedule A-25


Purchaser Name	CUNA MUTUAL INSURANCE SOCIETY
Signature Block	CUNA MUTUAL INSURANCE SOCIETY
	By:	MEMBERS Capital Advisors, Inc., acting as Investment Advisor
		By:
		Name: Allen R. Cantrell
		Title: Director, Investments
Tax identification number	39-0230590

Schedule A-26


Purchaser Name	CUMIS INSURANCE SOCIETY, INC.
Note Registration Number(s); Principal Amount(s)	TURNJETTY + CO
Note Registration Number(s); Principal Amount(s)	RH-9; $3,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer State Street Bank ABA #11000028 Account Name: Cumis Insurance Society DDA#: 1658-736-2 Reference Fund #ZT1i, Nominee Name TURNJETTY + CO Re: (See “Accompanying information” below)
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	Email: DS-PRIVATEPLACEMENTS@CUNAMUTUAL.COM
	CUMIS Insurance Society, Inc. c/o MEMBERS Capital Advisors, Inc. 5910 Mineral Point Road Madison, WI 53705-4456 Attn: Carrie Snell (carrie.snell@cunamutual.com) Fax: 608-231-8639
Address / Fax # for all other notices	Email: DS-PRIVATEPLACEMENTS@CUNAMUTUAL.COM
	CUMIS Insurance Society, Inc. c/o MEMBERS Capital Advisors, Inc. 5910 Mineral Point Road Madison, WI 53705-4456
	Attn:	Allen Cantrell (Al.Cantrell@cunamutual.com)
		John Britt (john.britt@cunamutual.com) Carrie Snell (carrie.snell@cunamutual.com)
	Fax:	608-236-8228 (Allen Cantrell)
		860-693-6402 (John Britt)
		608-231-8639 (Carrie Snell)
Instructions re Delivery of Notes	State Street Bank DTC/New York Window 55 Water Street Plaza Level – 3 ^rd Floor New York, NY 10041 Attn: Robert Mendez Ref: ZT1i / TURNJETTY + CO

Schedule A-27


Purchaser Name	CUMIS INSURANCE SOCIETY, INC.
Signature Block	CUMIS INSURANCE SOCIETY, INC.
	By:	MEMBERS Capital Advisors, Inc., acting as Investment Advisor
		By:
		Name:	Allen R. Cantrell
		Title:	Director, Investments
Tax identification number	39-0230590

Schedule A-28


Purchaser Name	COLONIAL LIFE & ACCIDENT INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	CUDD & CO.
Note Registration Number(s); Principal Amount(s)	RJ-6; $8,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer CUDD & CO. c/o JP Morgan Chase Bank New York, NY ABA No. 021 000 021 SSG Private Income Processing A/C #900-9-000200 Custodial Account No. G08292 Re: “Accompanying information” below
Accompanying information	Name of Issuer:		CABOT OIL & GAS CORPORATION
	Description of Security:		5.80% Series J Senior Notes due January 15, 2026
	PPN:		127097 D#7
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	Provident Investment Management, LLC Private Placements One Fountain Square Chattanooga, Tennessee 37402
	Telephone:	(423) 294-1172
	Fax:	(423) 294-3351
	Email:	privatecompliance@unum.com
Address / Fax # for all other notices	Provident Investment Management, LLC Private Placements One Fountain Square Chattanooga, Tennessee 37402
	Telephone:	(423) 294-1172
	Fax:	(423) 294-3351
	Email:	privatecompliance@unum.com
Instructions re Delivery of Notes	JP Morgan Chase Bank 4 Chase Metrotech Center, 3rd Floor Ground Floor Window Brooklyn, NY 11245-0001 Attn: Brian Cavanugh (Tel: 718-242-0264) Ref: Account No.: G08292 (Colonial Life & Accident Insurance Company)

Schedule A-29


Purchaser Name	COLONIAL LIFE & ACCIDENT INSURANCE COMPANY
Signature Block	COLONIAL LIFE & ACCIDENT INSURANCE COMPANY
	By:	Provident Investment Management, LLC
	Its:	Agent
		By:
		Name:
		Title:
Tax identification number	13-6022143 (CUDD & CO.)

Schedule A-30


Purchaser Name	CONNECTICUT GENERAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	CIG & CO.
Note Registration Number(s); Principal Amount(s)	RH-10; $1,000,000 RH-11; $1,000,000 RH-12; $1,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer JPMorgan Chase Bank BNF=CIGNA Private Placements/AC=9009001802 ABA# 021000021 OBI= “Accompanying Information” below.
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	CIG & Co. c/o CIGNA Investments, Inc. Attn: Fixed Income Securities Wilde Building, A5PRI 900 Cottage Grove Rd. Bloomfield, CT 06002 Fax: 860-226-8400 With a copy to : J.P. Morgan Chase Bank 14201 Dallas Parkway, 13 ^th Floor Dallas, TX 75254-2916 Attn: Rudy Paredes, Mail Code TX1-J222 Tel: 469-477-1960 Fax: 469-477-1904
Address / Fax # for all other notices	CIG & Co. c/o CIGNA Investments, Inc. Attn: Fixed Income Securities Wilde Building, A5PRI 900 Cottage Grove Rd. Bloomfield, CT 06002 Fax: 860-226-8400
Instructions re Delivery of Notes	J.P. Morgan Chase Bank 4 New York Plaza New York, NY 10004 Attn: Brian Cavanaugh Together with Transmittal to Securities Custodian Letter

Schedule A-31


Purchaser Name	CONNECTICUT GENERAL LIFE INSURANCE COMPANY
Signature Block	CONNECTICUT GENERAL LIFE INSURANCE COMPANY
	By:	CIGNA Investments, Inc. (authorized agent)
		By:
		Name:
		Title:
Tax identification number	13-3574027 (CIG & Co.)

Schedule A-32


Purchaser Name	LIFE INSURANCE COMPANY OF NORTH AMERICA
Note Registration Number(s); Principal Amount(s)	CIG & CO.
Note Registration Number(s); Principal Amount(s)	RH-13; $2,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer JPMorgan Chase Bank BNF=CIGNA Private Placements/AC=9009001802 ABA# 021000021 OBI= “Accompanying Information” below.
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	CIG & Co. c/o CIGNA Investments, Inc. Attn: Fixed Income Securities Wilde Building, A5PRI 900 Cottage Grove Rd. Bloomfield, CT 06002 Fax: 860-226-8400 With a copy to : J.P. Morgan Chase Bank 14201 Dallas Parkway, 13 ^th Floor Dallas, TX 75254-2916 Attn: Rudy Paredes, Mail Code TX1-J222 Tel: 469-477-1960 Fax: 469-477-1904
Address / Fax # for all other notices	CIG & Co. c/o CIGNA Investments, Inc. Attn: Fixed Income Securities Wilde Building, A5PRI 900 Cottage Grove Rd. Bloomfield, CT 06002 Fax: 860-226-8400
Instructions re Delivery of Notes	J.P. Morgan Chase Bank 4 New York Plaza New York, NY 10004 Attn: Brian Cavanaugh Together with Transmittal to Securities Custodian Letter

Schedule A-33


Purchaser Name	LIFE INSURANCE COMPANY OF NORTH AMERICA
Signature Block	LIFE INSURANCE COMPANY OF NORTH AMERICA
	By:	CIGNA Investments, Inc. (authorized agent)
		By:
		Name:
		Title:
Tax identification number		13-3574027 (CIG & Co.)

Schedule A-34


Purchaser Name	THE OHIO NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	THE OHIO NATIONAL LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RH-14; $2,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer U.S. Bank N.A. 5th & Walnut Streets Cincinnati, OH 45202 ABA #042-000013 For credit to The Ohio National Life Insurance Company’s Account No. 910-275-7 Re: “Accompanying Information” below.
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	The Ohio National Life Insurance Company Post Office Box 237 Cincinnati, OH 45201 Attention: Investment Department Fax: 513-794-4506 Street Address: One Financial Way Cincinnati, OH 45242
Address / Fax # for all other notices	The Ohio National Life Insurance Company Post Office Box 237 Cincinnati, OH 45201 Attention: Investment Department Fax: 513-794-4506 Street Address: One Financial Way Cincinnati, OH 45242
Instructions re Delivery of Notes	The Ohio National Life Insurance Company Attn: Investments One Financial Way Cincinnati, OH 45242

Schedule A-35


Purchaser Name		THE OHIO NATIONAL LIFE INSURANCE COMPANY
Signature Block		THE OHIO NATIONAL LIFE INSURANCE COMPANY
		By:
		Name:
		Title:
Tax identification number		31-0397080

Schedule A-36


Purchaser Name	OHIO NATIONAL LIFE ASSURANCE CORPORATION
Note Registration Number(s); Principal Amount(s)	OHIO NATIONAL LIFE ASSURANCE CORPORATION
Note Registration Number(s); Principal Amount(s)	RH-15; $1,000,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer U.S. Bank N.A. 5th & Walnut Streets Cincinnati, OH 45202 ABA #042-000013 For credit to Ohio National Life Assurance Corporation’s Account No. 865-215-8 Re: “Accompanying Information” below.
Accompanying information	Name of Issuer:	CABOT OIL & GAS CORPORATION
	Description of Security:	5.42% Series H Senior Notes due January 15, 2021
	PPN:	127097 D*1
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	Ohio National Life Assurance Corporation Post Office Box 237 Cincinnati, OH 45201 Attention: Investment Department Fax: 513-794-4506 Street Address: One Financial Way Cincinnati, OH 45242
Address / Fax # for all other notices	Ohio National Life Assurance Corporation Post Office Box 237 Cincinnati, OH 45201 Attention: Investment Department Fax: 513-794-4506 Street Address: One Financial Way Cincinnati, OH 45242
Instructions re Delivery of Notes	Ohio National Life Assurance Corporation Attn: Investments One Financial Way Cincinnati, OH 45242

Schedule A-37


Purchaser Name		OHIO NATIONAL LIFE ASSURANCE CORPORATION
Signature Block		OHIO NATIONAL LIFE ASSURANCE CORPORATION
		By:
		Name:
		Title:
Tax identification number		31-0962495

Schedule A-38


Purchaser Name	NATIONAL GUARDIAN LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	NATIONAL GUARDIAN LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RJ-7; $1,500,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer US Bank Madison PO Box 7900 Madison, WI 53707 ABA No. 075000022 For credit to: National Guardian Life Insurance Company Account No. 312 335 010 Ref: “Accompanying Information” below
Accompanying information	Name of Issuer:		CABOT OIL & GAS CORPORATION
	Description of Security:		5.80% Series J Senior Notes due January 15, 2026
	PPN:		127097 D#7
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	National Guardian Life Insurance Company Two E. Gilman St Madison, WI 53703 Attn: Investment Dept
Address / Fax # for all other notices	National Guardian Life Insurance Company Two E Gilman St Madison, WI 53703 Attn: Investment Dept
Instructions re Delivery of Notes	National Guardian Life Insurance Company Two E. Gilman Street Madison, WI 53703 Attn: Robert A. Mucci
Signature Block	NATIONAL GUARDIAN LIFE INSURANCE COMPANY
	By:
	Name:	Robert A. Mucci
	Title:	Senior Vice President & Treasurer
Tax identification number	39-0493780

Schedule A-39


Purchaser Name	SETTLERS LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	SETTLERS LIFE INSURANCE COMPANY
Note Registration Number(s); Principal Amount(s)	RJ-8; $500,000
Payment on account of Note Method Account information	Federal Funds Wire Transfer US Bank Madison PO Box 7900 Madison, WI 53707 ABA No. 075000022 For credit to: Settlers Life Insurance Company Account No. 182 380 404 778 Ref: “Accompanying Information” below
Accompanying information	Name of Issuer:		CABOT OIL & GAS CORPORATION
	Description of Security:		5.80% Series J Senior Notes due January 15, 2026
	PPN:		127097 D#7
	Due date and application (as among principal, interest and Make-Whole Amount) of the payment being made.
Address / Fax # for notices related to payments	Settlers Life Insurance Company Two E. Gilman St Madison, WI 53703 Attn: Investment Dept
Address / Fax # for all other notices	Settlers Life Insurance Company Two E Gilman St Madison, WI 53703 Attn: Investment Dept
Instructions re Delivery of Notes	Settlers Life Insurance Company Two E. Gilman Street Madison, WI 53703 Attn: Robert A. Mucci
Signature Block	SETTLERS LIFE INSURANCE COMPANY
	By:
	Name:	Robert A. Mucci
	Title:	Vice President & Treasurer
Tax identification number	47-0648948

Schedule A-40

Schedule B

D EFINED T ERMS

As used herein, the following terms have the respective meanings set forth below or set forth in the Section hereof following such term:

“ Adjusted Cash ” means, as of any date, the lesser of (a) the amount by which cash and short-term investments of the Company and its Subsidiaries exceed $5,000,000 and (b) the amount, if any, by which (i) current assets of the Company and its Subsidiaries exceed (ii) current liabilities of such Persons (excluding the aggregate outstanding principal amount of Indebtedness included in such current liabilities), in each case determined on a consolidated basis as of such date. If such current liabilities exceed such current assets, Adjusted Cash shall be zero.

“ Advance Payment Contract ” means (a) any production payment (whether volumetric or dollar denominated) granted or sold by any Person payable from a specified share of proceeds received from production from specified Petroleum Properties, together with all undertakings and obligations in connection therewith or (b) any contract whereby any Person receives or becomes entitled to receive (either directly or indirectly) any payment (an “ Advance Payment ”) as consideration for (i) Hydrocarbons produced or to be produced from Petroleum Properties owned by such Person or its Affiliates in advance of the delivery of such Hydrocarbons (and regardless of whether such Hydrocarbons are actually produced or actual delivery is required) to or for the account of the purchaser thereof or (ii) a right or option to receive such Hydrocarbons (or a cash payment in lieu of such Hydrocarbons); provided that inclusion of customary and standard “take or pay” provisions in any gas sales or purchase contract or any other similar contract shall not, in and of itself, cause such gas sales or purchase contract to constitute an Advance Payment Contract for the purposes of this definition.

“ Affiliate ” means each Person who controls, is controlled by or is under common control with the Company. For purposes of this definition, the term “control” means possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

“ Affiliated Entity ” means the Subsidiaries of the Company and any of their or the Company’s respective Controlled Affiliates. As used in this definition, “ Control ” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise.

“ Anti-Money Laundering Laws ” is defined in Section 5.16(c).

“ Bank Credit Agreement ” means the Amended and Restated Credit Agreement dated as of September 22, 2010 among the Company, JPMorgan Chase Bank, N.A., as administrative agent, Bank of America Securities LLC and Bank of Montreal as co-syndication agents, BNP Paribas and Wells Fargo Bank N.A., as co-documentation agents and the lenders from time to time party thereto, as such agreement hereafter may be amended, restated, supplemented, modified, refinanced, extended or replaced.

Schedule B-1

“ Blocked Person ” is defined in Section 5.16(a).

“ Borrowing Base ” shall have the meaning set forth in the Bank Credit Agreement.

“ Business Day ” means (a) for the purposes of Section 8.8 only, any day other than a Saturday, a Sunday or a day on which commercial banks in New York, New York are required or authorized to be closed, and (b) for the purposes of any other provision of this Agreement, any day other than a Saturday, a Sunday or a day on which commercial banks in New York, New York or Houston, Texas are required or authorized to be closed.

“ Capital Lease ” means, at any time, a lease with respect to which the lessee is required concurrently to recognize the acquisition of an asset and the incurrence of a liability in accordance with GAAP.

“ Capital Lease Obligations ” means with respect to a specified Person, the obligations of such Person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as Capital Leases, and the amount of such obligations shall be the capitalized amount thereof determined in accordance with GAAP.

“ Change of Control ” means any of the following events or circumstances (a) any Person or related Persons constituting a “group” for purposes of Section 13(d) of the Exchange Act shall have acquired “beneficial ownership” of a majority of the Voting Stock of the Company, or (b) during any period of 24 consecutive months, individuals who were directors of the Company at the beginning of the period and Qualifying Directors, in the aggregate, shall cease to constitute a majority of the Board of Directors of the Company.

Notwithstanding the foregoing, a “Change of Control” shall not be deemed to have occurred:

(1) if, immediately following the event that would otherwise constitute a Change of Control, the Company (or the acquiring Person if it has acquired substantially all of the assets of the Company, or the resulting or surviving Person if it has merged or consolidated with the Company and the Company is not the surviving entity) has a rating of BBB- or higher by Standard & Poor’s, a Division of McGraw Hill Companies or Baa3 or higher by Moody’s Investors Service, Inc. or an equivalent rating by another rating agency of recognized national standing if it has only a single rating or, if it has two or more ratings, at least two of the ratings are BBB- or higher by Standard & Poor’s, a Division of McGraw Hill Companies or Baa3 or higher by Moody’s Investors Service, Inc. or an equivalent rating by another rating agency of recognized national standing (in each case, with no negative outlook) (as used in this paragraph “rating” of a Person means a rating of long-term unsecured debt of such Person);

(2) if the event that would otherwise constitute a Change of Control occurs in connection with a transaction in which (i) 100% of the Voting Stock of the Company becomes and remains at all times owned by another entity (a “Permitted Holding Company”), (ii) a majority of the Voting Stock of the Permitted Holding Company is owned by persons who were the holders of a majority of the Voting Stock of the Company prior to such transaction, and (iii) individuals who were directors of the Company at the beginning of the period described in clause (b) of this definition and Qualifying Directors, in the aggregate, constitute a majority of the Board of Directors of the Permitted Holding Company ( provided that, after such transaction, the Permitted Holding Company shall be substituted for the Company for purposes of this definition of Change of Control); or

Schedule B-2

(3) upon a conversion of the Company into a limited liability company, limited partnership or other form of entity or an exchange of all of the outstanding equity interests of the Company for equity interests in another form of entity into which the Company has been converted, so long as following such conversion or exchange the persons who were the holders of the capital stock of, or other equity interests in, the Company immediately prior to such transactions own in the aggregate the majority of the equity interests of such entity into which the Company has been converted sufficient to elect a majority of its Board of Directors or persons performing a similar function.

“ Closing ” is defined in Section 3.

“ Code ” means the Internal Revenue Code of 1986, as amended from time to time, and the rules and regulations promulgated thereunder from time to time.

“ Company ” means Cabot Oil & Gas Corporation, a Delaware corporation or any successor that becomes such in the manner prescribed in Section 10.2.

“ Confidential Information ” is defined in Section 20.

“ Consolidated EBITDAX ” means, for any period, the sum of (a) Consolidated Net Income of the Company and its Subsidiaries for such period, plus (b) the following expenses or charges, without duplication and to the extent deducted in calculating such Consolidated Net Income for such period: (i) Consolidated Interest Expense, (ii) income and franchise taxes, (iii) depreciation, depletion, amortization, exploration and abandonment expenses, and intangible drilling costs, (iv) lease impairment expenses; (v) extraordinary losses (or less extraordinary gains) attributable to writeups or writedowns of assets, including ceiling test writedown and impairments of long-lived assets, (vi) other noncash charges, and (vii) to the extent expensed and recognized in such period, the transaction fees and expenses incurred on or about June 30, 2010 in connection with the negotiation, execution and closing of the amendments to existing financing arrangements in an aggregate amount not to exceed $4,000,000, minus (c) all noncash income added to Consolidated Net Income; provided that EBITDAX (and any defined term used herein) for any applicable period shall be calculated on a pro forma basis for any acquisitions or dispositions during such period, as if such acquisition or disposition had occurred on the first day of such period and, concurrently with such determination, the Company shall furnish to the holders of the Notes audited financial statements or other financing information with respect to such business entity demonstrating to the reasonable satisfaction of the Required Holders the basis for such computations.

“ Consolidated Interest Expense ” is defined in Section 10.9(c).

“ Consolidated Net Income ” means with respect to the Company and its Subsidiaries, for any period, the aggregate of the net income (or loss) of the Company and its Subsidiaries after allowances for taxes for such period determined on a consolidated basis in accordance with GAAP; provided that there shall be excluded from such net income (to the extent otherwise included therein) the following: (a) the net income of any Person in which the Company or any Subsidiary has an interest (which interest does not cause the net income of such other Person to be consolidated with the net income of the Company and its Subsidiaries in accordance with GAAP), except to the extent of the amount of dividends or distributions actually paid in cash during such period by such other Person to the Company or a Subsidiary, as the case may be; (b) the net income (but not loss) during such period of any Subsidiary to the extent that the declaration or payment of dividends or similar distributions or transfers or loans by such Subsidiary is not at the time permitted by operation of the terms of its charter or any agreement, instrument or Governmental Requirement applicable to such Subsidiary or is otherwise restricted or prohibited, in each case determined in accordance with GAAP; (c) the net income (or loss) of any Person acquired in a pooling-of-interests transaction for any period prior to the date of such transaction; (d) any extraordinary gains or losses during such period and (e) any gains or losses attributable to writeups or writedowns of assets, including ceiling test writedowns and impairments of long-lived assets.

Schedule B-3

“ Consolidated Total Assets ” means, as of any date, the assets and properties of the Company and its Subsidiaries as of such date, determined on a consolidated basis in accordance with GAAP; provided, however, that Consolidated Total Assets shall be determined without giving effect to non-cash charges associated with successful efforts impairment test accounting or other similar tests resulting in non-cash charges.

“ Control Event ” means the execution of any written agreement which, when fully performed by the parties thereto, would result in a Change in Control.

“ Crude Oil ” means all crude oil and condensate.

“ Debt Prepayment Application ” means, with respect to any Disposition under Section 10.6(e) of any assets, the application by the Company or any Subsidiary, as the case may be, of cash in an amount equal to the net proceeds with respect to such Disposition to pay Senior Indebtedness (other than (a) Senior Indebtedness owing to the Company or any of its Subsidiaries or any Affiliate and (b) Senior Indebtedness in respect of any revolving credit or similar facilities providing the Company or any Subsidiary with the right to obtain loans or other extensions of credit from time to time, unless in connection with such payment of Senior Indebtedness the availability of credit under such credit facility is permanently reduced by an amount not less than the amount of such prepayment), provided that in the course of making such application the Company shall offer to prepay each outstanding Note, in accordance with Section 8.4, in a principal amount which equals the Ratable Portion of such Note in respect of such Disposition.

“ Debt Prepayment Transfer ” is defined in Section 8.4(a).

“ Default ” means an event or condition the occurrence or existence of which would, with the lapse of time or the giving of notice or both, become an Event of Default.

“ Default Rate ” means, with respect to any Note, that rate of interest that is equal to the greater of (a) 2% per annum above the rate of interest stated in clause (a) of the first paragraph of the Notes or (b) 2% over the rate of interest publicly announced by JPMorgan Chase Bank, N.A. from time to time at its principal office in New York, New York as its “base” or “prime” rate.

Schedule B-4

“ Disposition ” is defined in Section 10.6

“ Electronic Delivery ” is defined in Section 7.1(a).

“ Environmental Laws ” means any and all federal, state, local and foreign statutes, laws, regulations, ordinances, rules, judgments, orders, decrees, permits, concessions, grants, franchises, licenses, agreements or other governmental restrictions relating to the environment or to emissions, discharges or releases of pollutants, contaminants, petroleum or petroleum products (including natural gas), chemicals or industrial, toxic or hazardous substances or wastes into the environment including, without limitation, ambient air, surface water, ground water, or land, or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollutants, contaminants, petroleum or petroleum products (including natural gas), chemicals or industrial, toxic or hazardous substances or wastes or the clean-up or other remediation thereof, including the Oil Pollution Act of 1990 (“OPA”), as amended, the Clean Air Act, as amended, the Comprehensive Environmental, Response, Compensation, and Liability Act of 1980 (“CERCLA”), as amended, the Federal Water Pollution Control Act, as amended, the Occupational Safety and Health Act of 1970, as amended, the Resource Conservation and Recovery Act of 1976 (“RCRA”), as amended, the Safe Drinking Water Act, as amended, the Toxic Substances Control Act, as amended and the Superfund Amendments and Reauthorization Act of 1986, as amended, and the Hazardous Materials Transportation Law, as amended.

“ Environmental Liability ” means any liability, contingent or otherwise (including any liability for damages, costs or environmental remediation, fines, penalties or indemnities), of the Company or any of its Subsidiaries directly or indirectly resulting from or based upon (a) violation of any Environmental Law, (b) the generation, use, handling, transportation, storage, treatment or disposal of any Hazardous Materials, (c) exposure to any Hazardous Materials, (d) the release or any Hazardous Materials into the environment or (e) any contract or agreement or other consensual arrangement pursuant to which liability is assumed or imposed with respect to the foregoing.

“ ERISA ” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and the rules and regulations promulgated thereunder from time to time in effect.

“ ERISA Affiliate ” means any trade or business (whether or not incorporated) that is treated as a single employer together with the Company under section 414 of the Code.

“ ERISA Event ” means (a) any “reportable event”, as defined in Section 4043 of ERISA or the regulations issued thereunder with respect to a Plan (other than an event for which the 30-day notice period is waived); (b) the existence with respect to any Plan of an “accumulated funding deficiency” (as defined in Section 412 of the Code or Section 302 of ERISA), whether or not waived; (c) the filing pursuant to Section 412(d) of the Code or Section 303(d) of ERISA of an application for a waiver of the minimum funding standard with respect to any Plan; (d) the incurrence by the Company or any of its ERISA Affiliates of any liability under Title IV of ERISA with respect to the termination of any Plan; (e) the receipt by the Company or any ERISA Affiliate from the PBGC or a plan administrator of any notice relating to an intention to terminate any Plan or Plans or to appoint a trustee to administer any Plan; (f) the incurrence by the Company or any of its ERISA Affiliates of any liability with respect to the withdrawal or partial withdrawal from any Plan or Multiemployer Plan; or (g) the receipt by the Company or any ERISA Affiliate of any notice, or the receipt by any Multiemployer Plan from the Company or any ERISA Affiliate of any notice, concerning the imposition of withdrawal liability or a determination that a Multiemployer Plan is, or is expected to be, insolvent or in reorganization, within the meaning of Title IV of ERISA.

Schedule B-5

“ Event of Default ” is defined in Section 11.

“ Exchange Act ” means the Securities Exchange Act of 1934, as amended, or any successor statute. For purposes of the definitions of “Change of Control” and “Qualifying Director,” unless otherwise defined in such Sections, the terms enclosed in quotation marks as used therein have the meanings ascribed to such terms under the Exchange Act and the rules and regulations promulgated by the Securities and Exchange Commission thereunder.

“ Form 10-K ” is defined in Section 7.1(b).

“ Form 10-Q ” is defined in Section 7.1(a).

“ GAAP ” means generally accepted accounting principles as in effect from time to time in the United States of America.

“ Governmental Authority ” means

(a) the government of

(i) the United States of America or any State or other political subdivision thereof, or

(ii) any other jurisdiction in which the Company or any Subsidiary conducts all or any part of its business, or which asserts jurisdiction over any properties of the Company or any Subsidiary, or

(b) any entity exercising executive, legislative, judicial, regulatory or administrative functions of, or pertaining to, any such government.

“ Governmental Requirement ” means any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, rules of common law, authorization or other directive or requirement, whether now or hereinafter in effect, of any Governmental Authority.

“ Guaranty ” means, with respect to any Person, any obligation (except the endorsement in the ordinary course of business of negotiable instruments for deposit or collection) of such Person guaranteeing or in effect guaranteeing any indebtedness, dividend or other obligation of any other Person in any manner, whether directly or indirectly, including (without limitation) obligations incurred through an agreement, contingent or otherwise, by such Person:

(a) to purchase such indebtedness or obligation or any property constituting security therefor;

Schedule B-6

(b) to advance or supply funds (i) for the purchase or payment of such indebtedness or obligation, or (ii) to maintain any working capital or other balance sheet condition or any income statement condition of any other Person or otherwise to advance or make available funds for the purchase or payment of such indebtedness or obligation;

(c) to lease properties or to purchase properties or services primarily for the purpose of assuring the owner of such indebtedness or obligation of the ability of any other Person to make payment of the indebtedness or obligation; or

(d) otherwise to assure the owner of such indebtedness or obligation against loss in respect thereof.

In any computation of the indebtedness or other liabilities of the obligor under any Guaranty, the indebtedness or other obligations that are the subject of such Guaranty shall be assumed to be direct obligations of such obligor.

“ Hazardous Material ” means any substance regulated or as to which liability might arise under any applicable Environmental Law including: (a) any chemical, compound, material, product, byproduct, substance or waste defined as or included in the definition or meaning of “hazardous substance,” “hazardous material,” “hazardous waste,” “solid waste,” “toxic waste,” “extremely hazardous substance,” “toxic substance,” “contaminant,” “pollutant,” or words of similar meaning or import found in any applicable Environmental Law; (b) Hydrocarbons, petroleum products, petroleum substances, natural gas, oil, oil and gas waste, crude oil, and any components, fractions, or derivatives thereof; and (c) radioactive materials, explosives, asbestos or asbestos containing materials, polychlorinated biphenyls, radon, infectious or medical wastes.

“ holder ” means, with respect to any Note the Person in whose name such Note is registered in the register maintained by the Company pursuant to Section 13.1.

“ Hydrocarbon ” means all Crude Oil and Natural Gas produced from or attributable to the Petroleum Properties of the Company and its Subsidiaries.

“ Indebtedness ” of any Person means, without duplication, (a) all obligations of such Person for borrowed money or with respect to deposits or advances of any kind, (b) all obligations of such Person evidenced by bonds, debentures, notes or similar instruments, (c) all obligations of such Person upon which interest charges are customarily paid (excluding current accounts payable incurred in the ordinary course of business), (d) all obligations of such Person under conditional sale or other title retention agreements relating to property acquired by such Person, (e) all obligations of such Person in respect of the deferred purchase price of property or services (excluding current accounts payable incurred in the ordinary course of business), (f) all Indebtedness of others secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien on property owned or acquired by such Person, whether or not the Indebtedness secured thereby has been assumed, (g) all Guaranties by such Person of Indebtedness of others, (h) all Capital Lease Obligations of such Person, (i) all obligations, contingent or otherwise, of such Person as an account party in respect of letters of credit and letters of guaranty, (j) all obligations, contingent or otherwise, of such Person in respect of bankers’ acceptances and (k) all obligations of such Person with respect to Advance Payment Contracts to which such Person is a party. The Indebtedness of any Person shall include the Indebtedness of any other entity (including any partnership in which such Person is a general partner) to the extent such Person is liable therefor as a result of such Person’s ownership interest in or other relationship with such entity, except to the extent the terms of such Indebtedness provide that such Person is not liable therefor.

Schedule B-7

“ Indebtedness and Other Liabilities ” means, at any date, the sum of, without duplication, (a) Indebtedness (under clauses (a) through and including (h) of such definition) of the Company and its Subsidiaries at such date, plus (b) the amount, if any, by which Negative Adjusted Working Capital at such date exceeds 6% of the Present Value of Proved Reserves, minus (c) Non-Recourse Debt of the Company and its Subsidiaries at such date.

“ Institutional Investor ” means (a) any Purchaser of a Note, (b) any holder of a Note holding (together with one or more of its affiliates) more than 5% of the aggregate principal amount of the Notes then outstanding, (c) any bank, trust company, savings and loan association or other financial institution, any pension plan, any investment company, any insurance company, any broker or dealer, or any other similar financial institution or entity, regardless of legal form, and (d) any Related Fund of any holder of any Note.

“ Intercompany Indebtedness ” means Indebtedness of Wholly-Owned Subsidiaries owing to the Company.

“ Lien ” means, with respect to any asset, (a) any mortgage, deed of trust, lien, pledge, hypothecation, encumbrance, charge or security interest in, on or of such asset, (b) the interest of a vendor or a lessor under any conditional sale agreement, Capital Lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset and (c) in the case of securities, any purchase option, call or similar right of a third party with respect to such securities (other than customary director, officer and employee stock option plans and “poison pill” plans).

“ Make-Whole Amount ” is defined in Section 8.8.

“ Material ” means material in relation to the business, operations, affairs, financial condition, assets, properties, or prospects of the Company and its Subsidiaries taken as a whole.

“ Material Subsidiary ” means any Subsidiary of the Company representing more than 5% of Consolidated Total Assets or 5% of total revenue (for the immediately preceding four fiscal quarters) of the Company and its Subsidiaries.

“ Material Adverse Effect ” means a material adverse effect on (a) the business, operations, affairs, financial condition, assets or properties of the Company and its Subsidiaries taken as a whole, or (b) the ability of the Company to perform its obligations under this Agreement and the Notes, or (c) the validity or enforceability of this Agreement or the Notes.

Schedule B-8

“ Memorandum ” is defined in Section 5.3.

“ Multiemployer Plan ” means any Plan that is a “multiemployer plan” (as such term is defined in section 4001(a)(3) of ERISA).

“ NAIC ” means the National Association of Insurance Commissioners or any successor thereto.

“ Natural Gas ” means all natural gas, distillate or sulphur, natural gas liquids and all products recovered in the processing of natural gas (other than condensate) including, without limitation, natural gasoline, coalbed methane gas, casinghead gas, iso-butane, normal butane, propane and ethane (including such methane allowable in commercial ethane).

“ Negative Adjusted Working Capital ” means, at any date, the amount, if any, by which current liabilities other than Indebtedness (under clauses (a) through and including (h) of such definition) of the Company and its Subsidiaries exceeds current assets of such Persons, determined on a consolidated basis as of such date.

“ Non-Recourse Debt ” of any Person means Indebtedness of such Person in respect of which (a) the recourse of the holder of such Indebtedness, whether direct or indirect and whether contingent or otherwise, is effectively limited to the assets directly securing such Indebtedness; (b) such holder may not collect by levy of execution against assets of such Person generally (other than the assets directly securing such Indebtedness) if such Person fails to pay such Indebtedness when due and the holder obtains a judgment with respect thereto; and (c) such holder has waived, to the extent such holder may effectively do so, such holder’s right to elect recourse treatment under 11 U.S.C. (S) 1111(b).

“ Notes ” is defined in Section 1.

“ OFAC ” is defined in Section 5.16(a).

“ OFAC Listed Person ” is defined in Section 5.16(a).

“ Officer’s Certificate ” means a certificate of a Senior Financial Officer or of any other officer of the Company whose responsibilities extend to the subject matter of such certificate.

“ PBGC ” means the Pension Benefit Guaranty Corporation referred to and defined in ERISA or any successor thereto.

“ Pension Funding Rules ” means the rules of the Code and ERISA regarding minimum required contributions (including any installment payment thereof) to Plans and set forth in, with respect to plan years ending prior to the effective date as to any such Plan of the Pension Protection Act of 2006, Sections 401(a)(29) and 412 of the Code and Part 3, Subtitle I, of Title I of ERISA each as in effect prior to the Pension Protection Act of 2006 and, thereafter, Sections 412 and 430 through 436 of the Code and Part 3, Subtitle I, of Title I of ERISA each as in effect from time to time.

Schedule B-9

“ Permitted Encumbrances ” means:

(a) Liens for taxes, assessments, or similar charges, incurred in the ordinary course of business that are not yet due and payable;

(b) Liens of mechanics, materialmen, warehousemen, carriers, landlords or other like liens (including, without limitation, liens arising in favor of sellers of hydrocarbons), securing obligations incurred in the ordinary course of business that are not yet due and payable;

(c) Pledges or deposits in connection with or to secure workmen’s compensation, unemployment insurance, pensions or other employee benefits;

(d) Encumbrances consisting of covenants, zoning restrictions, rights, easements, liens, governmental environmental permitting and operation restrictions, operating restrictions under leases, the exercise by governmental bodies or third parties of eminent domain or condemnation rights, or any other restrictions on the use of real property, none of which materially impairs the use of such property by the Company or its Subsidiaries in the operation of its business, and none of which is violated in any material respect by existing or proposed operations;

(e) Liens of operators and/or co-working interest owners under joint operating agreements or similar contractual arrangements with respect to the Company’s or its Subsidiaries’ proportionate share of the expense of exploration, development and operation of oil, gas and mineral leasehold or fee interests owned jointly with others, to the extent that same relate to sums not yet overdue, or if they relate to sums that are overdue, then to the extent that the same are being contested in good faith by appropriate proceedings and with respect to which adequate reserves are set aside on its books;

(f) Liens arising in the ordinary course of business under farm-out agreements, gas sales contracts, operating agreements, unitization and pooling agreements, and such other documents as are customarily found in connection with comparable drilling and producing operations;

(g) letters of credit, pledges or deposits, including bonds, required in the ordinary course of business to secure public or statutory obligations or to secure performance in connection with bids or contracts relating to the exploration or development of Petroleum Properties, to the extent that payment of the underlying obligations is not yet due or is being contested in good faith by appropriate proceedings by or on behalf of the Company or a Subsidiary and with respect to which appropriate reserves have been established;

(h) Liens representing gas imbalances;

(i) The following, if the validity or amount thereof is being contested in good faith by appropriate and lawful proceedings and with respect to which adequate reserves are set aside on its books, and so long as they do not, in the aggregate, materially detract from the value of the property of the Company, or materially impair the use thereof in the operation of its business:

(1) Claims or liens for taxes, assessments, or charges due and payable and subject to interest or penalty;

Schedule B-10

(2) Claims, liens, and encumbrances upon, and defects of title to, real or personal property, including any attachment of personal or real property or other legal process prior to adjudication of a dispute on the merits;

(3) Claims or liens of mechanics, materialmen, warehousemen, carriers, or other like liens (including, without limitation, liens arising in form of sellers of hydrocarbons); and

(4) Adverse judgments on appeal; and

(i)

Inchoate liens in respect of royalty owners;

provided that the term “Permitted Encumbrances” shall not include any Lien securing Indebtedness except as provided in clause (h) to the extent consisting of any Advance Payment Contracts.

“ Person ” means an individual, partnership, corporation, limited liability company, association, trust, unincorporated organization, business entity or Governmental Authority.

“ Petroleum Property ” means any interest of the Company or any Subsidiary in oil and gas reserves and assets consisting primarily of gas gathering, processing and storage facilities and transmission pipelines.

“ Plan ” means an “employee benefit plan” (as defined in section 3(3) of ERISA) subject to Title I of ERISA that is or, within the preceding five years, has been established or maintained, or to which contributions are or, within the preceding five years, have been made or required to be made, by the Company or any ERISA Affiliate or with respect to which the Company or any ERISA Affiliate may have any liability.

“ Present Value of Proved Reserves ” means, at any time, the net present value, discounted at 10% per annum, of the future after-tax net revenues expected to accrue to the Company’s and its Subsidiaries’ collective interests in Proved Reserves expected to be produced from their Petroleum Properties during the remaining expected economic lives of such reserves. Each calculation of such expected future net revenues shall be made in accordance with the then existing standards of the Society of Petroleum Engineers, provided that in any event (a) appropriate deductions shall be made for severance and ad valorem taxes, and for operating, gathering, transportation and marketing costs required for the production and sale of such reserves, (b) appropriate adjustments shall be made for hedging operations, provided that Swap Agreements with non-investment grade counterparties shall not be taken into account to the extent that such Swap Agreements improve the position of or otherwise benefit the Company or any of its Subsidiaries, (c) the pricing assumptions used in determining net present value for any particular reserves shall be based upon the following price decks: (i) for natural gas, the quotation for deliveries of natural gas for each such year from the New York Mercantile Exchange for Henry Hub, provided that with respect to quotations for calendar years after the fifth calendar year, the quotation for the fifth calendar year shall be applied and (ii) for crude oil, the quotation for deliveries of West Texas Intermediate crude oil for each such calendar year from the New York Mercantile Exchange for Cushing, Oklahoma, provided that with respect to quotations for calendar years after the fifth calendar year, the quotation for the fifth calendar year shall be applied, and (d) the cash-flows derived from the pricing assumptions set forth in clause (c) above shall be further adjusted to account for the historical basis differentials for each month during the preceding 12-month period calculated by comparing realized crude oil and natural gas prices to Cushing, Oklahoma and Henry Hub NYMEX prices for each month during such period; provided that in calculating the Present Value of Proved Reserves, Proved Undeveloped Reserves shall not be taken into account to the extent that more than 30% of the Present Value of Proved Reserves is attributable to Proved Undeveloped Reserves.

Schedule B-11

“ Priority Debt ” means, as of any date, the sum (without duplication) of (a) Indebtedness of the Company or any of its Subsidiaries secured by Liens not otherwise permitted by Sections 10.5(a) through (k) and (b) Indebtedness of Subsidiaries other than (i) Indebtedness of a Subsidiary outstanding on date hereof and set forth in Schedule 5.15, and any extension, renewal, refinancing or refunding, provided that the principal amount of such Indebtedness is not increased; (ii) Indebtedness of a Subsidiary owed to the Company or a Subsidiary Guarantor; (iii) Indebtedness of a Subsidiary that is not a Subsidiary Guarantor owed to a Subsidiary; (iv) Indebtedness of a Subsidiary outstanding at the time it becomes a Subsidiary and extensions, renewals and refundings thereof, provided that (x) such Indebtedness shall not have been incurred in contemplation of such Subsidiary becoming a Subsidiary, (y) immediately after such Subsidiary becomes a Subsidiary, no Default or Event of Default shall exist (z) such Indebtedness is not outstanding for more than one year from the date such entity becomes a Subsidiary; and (v) Indebtedness of a Subsidiary Guarantor.

“ property ” or “properties” means, unless otherwise specifically limited, real or personal property of any kind, tangible or intangible, choate or inchoate.

“ Proposed Prepayment Date ” is defined in Section 8.3(b).

“ Proved Developed Non-Producing Reserves ” has the meaning assigned to that term by the Society of Petroleum Engineers, as it may be amended from time to time, but generally shall mean the subcategory of “Proved Developed Reserves” (as defined by the Society of Petroleum Engineers) which will become “Proved Developed Producing Reserves” upon minor capital expenditures being made with respect to existing wells which will cause formerly non-producing completions or intervals to become open and producing to market.

“ Proved Developed Producing Reserves ” has the meaning assigned to that term by the Society of Petroleum Engineers, as it may be amended from time to time, but generally shall mean the subcategory of “Proved Developed Reserves” (as defined by the Society of Petroleum Engineers) which are recoverable by natural reservoir energies (including pumping) from the completion intervals currently open and producing to market. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as “Proved Developed Producing Reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response through existing completions producing to market that increased recovery will be achieved. Proved Developed Producing Reserves shall not include any Proved Developed Non-Producing Reserves.

Schedule B-12

“ Proved Reserves ” means and includes Proved Developed Producing Reserves, Proved Developed Non-Producing Reserves and Proved Undeveloped Reserves.

“ Proved Undeveloped Reserves ” has the meaning assigned to that term by the Society of Petroleum Engineers, as it may be amended from time to time, but generally shall mean those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved Undeveloped Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved Undeveloped Reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for Proved 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 tests in the area and in the same reservoir.

“ PTE ” is defined in Section 6.2(a).

“ Purchaser ” is defined in the first paragraph of this Agreement.

“ Qualified Institutional Buyer ” means any Person who is a “qualified institutional buyer” within the meaning of such term as set forth in Rule 144A(a)(1) under the Securities Act.

“ Qualifying Directors ” means any director who (a) is elected by a majority of the members of the board of directors of the Company who were directors immediately prior to the event that caused the change in directorships and (b) is not a “person” or member of a “group” of persons, or an “affiliate” or “associate” of any “person” or “group” member, or an “associate” of an “affiliate” of any such “person” or “group” member, which “person” or “group” of persons, together with all of their respective “affiliates” and “associates” and all “associates” of their respective “affiliates” (other than a “person” or “group” of persons or an “affiliate” or “associate” of such “person” or “group” of persons or an “associate” of such “affiliate” in each case which is affiliated with the Company or any Subsidiary) comprise a majority of the board of directors of the Company.

“ Ratable Portion ” means, in respect of any holder of any Note upon any Disposition under Section 10.6(e), an amount equal to the product of

(a) the net proceeds arising from such Disposition being offered to be applied to the payment of Senior Indebtedness pursuant to Section 10.6(iii)(B), multiplied by

(b) a fraction, the numerator of which is the outstanding principal amount of such holder’s Note, and the denominator of which is the aggregate outstanding principal amount of all Senior Indebtedness at the time of such Disposition determined on a consolidated basis in accordance with GAAP.

Schedule B-13

“ Related Fund ” means, with respect to any holder of any Note, any fund or entity that (i) invests in Securities or bank loans, and (ii) is advised or managed by such holder, the same investment advisor as such holder or by an affiliate of such holder or such investment advisor.

“ Required Holders ” means, at any time, the holders of at least a majority in principal amount of the Notes at the time outstanding (exclusive of Notes then owned by the Company or any of its Affiliates).

“ Reserve Report ” means the reserve report delivered to the Purchasers for the fiscal year ended December 31, 2009, the interim reserve report dated June 30, 2010 and subsequently, a report delivered by the Company pursuant to Section 7.1(g).

“ Responsible Officer ” means any Senior Financial Officer and any other officer of the Company with responsibility for the administration of the relevant portion of this Agreement.

“ SEC ” shall mean the Securities and Exchange Commission of the United States, or any successor thereto.

“ Securities ” or “ Security ” shall have the meaning specified in Section 2(1) of the Securities Act.

“ Securities Act ” means the Securities Act of 1933, as amended from time to time, and the rules and regulations promulgated thereunder from time to time in effect.

“ Senior Indebtedness ” means the Notes and any Indebtedness of the Company or its Subsidiaries that by its terms is not in any manner subordinated in right of payment to any other unsecured Indebtedness of the Company or any Subsidiary.

“ Senior Financial Officer ” means the chief financial officer, principal accounting officer, treasurer or comptroller of the Company.

“ Series ” means any one or more of the series of Notes issued hereunder.

“ Series H Notes ” is defined in Section 1(a).

“ Series I Notes ” is defined in Section 1(b).

“ Series J Notes ” is defined in Section 1(c).

“ Subsidiary ” means, as to any Person, any other Person in which such first Person or one or more of its Subsidiaries or such first Person and one or more of its Subsidiaries owns sufficient equity or voting interests to enable it or them (as a group) ordinarily, in the absence of contingencies, to elect a majority of the directors (or Persons performing similar functions) of such second Person, and any partnership or joint venture if more than a 50% interest in the profits or capital thereof is owned by such first Person or one or more of its Subsidiaries or such first Person and one or more of its Subsidiaries (unless such partnership or joint venture can and does ordinarily take major business actions without the prior approval of such Person or one or more of its Subsidiaries). Unless the context otherwise clearly requires, any reference to a “Subsidiary” is a reference to a Subsidiary of the Company.

Schedule B-14

“ Subsidiary Guaranty ” is defined in Section 9.8 and includes any guaranty executed and delivered after the date of Closing by a Material Subsidiary pursuant to Section 9.8.

“ Subsidiary Guarantor ” means any Subsidiary of the Company that hereafter executes and delivers a guaranty to each holder of Notes pursuant to Section 9.8.

“ SVO ” means the Securities Valuation Office of the NAIC or any successor to such Office.

“ Swap Agreement ” means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions; provided that no phantom stock or similar plan providing for payments only on account of services provided by current or former directors, officers, employees or consultants of the Company or the Subsidiaries shall be a Swap Agreement.

“ Transfer Prepayment Date ” is defined in Section 8.4(a).

“ Transfer Prepayment Offer ” is defined in Section 8.4(a).

“ USA Patriot Act ” means United States Public Law 107-56, Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism (USA PATRIOT ACT) Act of 2001, as amended from time to time, and the rules and regulations promulgated thereunder from time to time in effect.

“ Voting Stock ” means, with respect to any Person, any class of shares of stock or other equity interests of such Person having general voting power under ordinary circumstances to elect the board of directors or other managing entities, as appropriate, of such Person (irrespective of whether or not at the time stock of any other class or classes or other equity interests of such Person shall have or might have voting power by reason of the happening of any contingency).

“ Wholly-Owned Subsidiary ” means, at any time, any Subsidiary one hundred percent of all of the equity interests (except directors’ qualifying shares) and voting interests of which are owned by any one or more of the Company and the Company’s other Wholly-Owned Subsidiaries at such time.

Schedule B-15

Exhibit 1(a)

F ORM OF S ERIES H N OTE

CABOT OIL & GAS CORPORATION

5.42% S ERIES H S ENIOR N OTE D UE J ANUARY 15, 2021


No. RH-[ ]		[Date]
$[ ]		PPN: 127097 D*1

For Value Received, the undersigned, CABOT OIL & GAS CORPORATION (herein called the “ Company ”), a corporation organized and existing under the laws of the State of Delaware, hereby promises to pay to [ ] , or registered assigns, the principal sum of [ ] DOLLARS (or so much thereof as shall not have been prepaid) on January 15, 2021, with interest (computed on the basis of a 360-day year of twelve 30-day months) (a) on the unpaid balance hereof at the rate of 5.42% per annum from the date hereof, payable semiannually, on the 15th day of January and July in each year, commencing with the July next succeeding the date hereof, until the principal hereof shall have become due and payable, and (b) to the extent permitted by law, on any overdue payment of interest and, during the continuance of an Event of Default, on such unpaid balance and on any overdue payment of any Make-Whole Amount, at a rate per annum from time to time equal to the greater of (i) 7.42% or (ii) 2% over the rate of interest publicly announced by JPMorgan Chase Bank, N.A. from time to time in New York, New York as its “base” or “prime” rate, payable semiannually as aforesaid (or, at the option of the registered holder hereof, on demand).

Payments of principal of, interest on and any Make-Whole Amount with respect to this Note are to be made in lawful money of the United States of America at the principal office of JPMorgan Chase Bank, N.A. in New York, New York or at such other place as the Company shall have designated by written notice to the holder of this Note as provided in the Note Purchase Agreement referred to below.

This Note is one of the Series H Senior Notes (herein called the “ Notes ”) issued pursuant to the Note Purchase Agreement, dated as of December 30, 2010 (as from time to time amended, the “ Note Purchase Agreement ”), between the Company and the respective Purchasers named therein and is entitled to the benefits thereof. Each holder of this Note will be deemed, by its acceptance hereof, to have (i) agreed to the confidentiality provisions set forth in Section 20 of the Note Purchase Agreement and (ii) made the representation set forth in Section 6.2 of the Note Purchase Agreement. Unless otherwise indicated, capitalized terms used in this Note shall have the respective meanings ascribed to such terms in the Note Purchase Agreement.

This Note is a registered Note and, as provided in the Note Purchase Agreement, upon surrender of this Note for registration of transfer accompanied by a written instrument of transfer duly executed, by the registered holder hereof or such holder’s attorney duly authorized in writing, a new Note for a like principal amount will be issued to, and registered in the name of, the transferee. Prior to due presentment for registration of transfer, the Company may treat the person in whose name this Note is registered as the owner hereof for the purpose of receiving payment and for all other purposes, and the Company will not be affected by any notice to the contrary.

This Note is also subject to optional prepayment, in whole or from time to time in part, at the times and on the terms specified in the Note Purchase Agreement, but not otherwise.

If an Event of Default occurs and is continuing, the principal of this Note may be declared or otherwise become due and payable in the manner, at the price (including any applicable Make-Whole Amount) and with the effect provided in the Note Purchase Agreement.

This Note shall be construed and enforced in accordance with, and the rights of the Company and the holder of this Note shall be governed by, the law of the State of New York excluding choice-of-law principles of the law of such State that would permit the application of the laws of a jurisdiction other than such State.


Very truly yours,

CABOT OIL & GAS CORPORATION

By


Name:
Title:

Exhibit 1(b)

F ORM OF S ERIES I N OTE

CABOT OIL & GAS CORPORATION

5.59% S ERIES I S ENIOR N OTE D UE J ANUARY 15, 2023


No. RI-[ ]		[Date]
$[ ]		PPN: 127097 D@9

For Value Received, the undersigned, CABOT OIL & GAS CORPORATION (herein called the “ Company ”), a corporation organized and existing under the laws of the State of Delaware, hereby promises to pay to [ ] , or registered assigns, the principal sum of [ ] DOLLARS (or so much thereof as shall not have been prepaid) on [ ], with interest (computed on the basis of a 360-day year of twelve 30-day months) (a) on the unpaid balance hereof at the rate of 5.59% per annum from the date hereof, payable semiannually, on the 15th day of January and July in each year, commencing with the July next succeeding the date hereof, until the principal hereof shall have become due and payable, and (b) to the extent permitted by law, on any overdue payment of interest and, during the continuance of an Event of Default, on such unpaid balance and on any overdue payment of any Make-Whole Amount, at a rate per annum from time to time equal to the greater of (i) 7.59% or (ii) 2% over the rate of interest publicly announced by JPMorgan Chase Bank, N.A. from time to time in New York, New York as its “base” or “prime” rate, payable semiannually as aforesaid (or, at the option of the registered holder hereof, on demand).

This Note is one of the Series I Senior Notes (herein called the “ Notes ”) issued pursuant to the Note Purchase Agreement, dated as of December 30, 2010 (as from time to time amended, the “ Note Purchase Agreement ”), between the Company and the respective Purchasers named therein and is entitled to the benefits thereof. Each holder of this Note will be deemed, by its acceptance hereof, to have (i) agreed to the confidentiality provisions set forth in Section 20 of the Note Purchase Agreement and (ii) made the representation set forth in Section 6.2 of the Note Purchase Agreement. Unless otherwise indicated, capitalized terms used in this Note shall have the respective meanings ascribed to such terms in the Note Purchase Agreement.

This Note is also subject to optional prepayment, in whole or from time to time in part, at the times and on the terms specified in the Note Purchase Agreement, but not otherwise.


Very truly yours,

CABOT OIL & GAS CORPORATION

By


Name:
Title:

Exhibit 1(c)

F ORM OF S ERIES J N OTE

CABOT OIL & GAS CORPORATION

5.80% S ERIES J S ENIOR N OTE D UE J ANUARY 15, 2026


No. RJ-[ ]		[Date]
$[ ]		PPN: 127097 D#7

For Value Received, the undersigned, CABOT OIL & GAS CORPORATION (herein called the “ Company ”), a corporation organized and existing under the laws of the State of Delaware, hereby promises to pay to [ ] , or registered assigns, the principal sum of [ ] DOLLARS (or so much thereof as shall not have been prepaid) on [ ], with interest (computed on the basis of a 360-day year of twelve 30-day months) (a) on the unpaid balance hereof at the rate of 5.80% per annum from the date hereof, payable semiannually, on the 15th day of January and July in each year, commencing with the July next succeeding the date hereof, until the principal hereof shall have become due and payable, and (b) to the extent permitted by law, on any overdue payment of interest and, during the continuance of an Event of Default, on such unpaid balance and on any overdue payment of any Make-Whole Amount, at a rate per annum from time to time equal to the greater of (i) 7.80% or (ii) 2% over the rate of interest publicly announced by JPMorgan Chase Bank, N.A. from time to time in New York, New York as its “base” or “prime” rate, payable semiannually as aforesaid (or, at the option of the registered holder hereof, on demand).

This Note is one of the Series J Senior Notes (herein called the “ Notes ”) issued pursuant to the Note Purchase Agreement, dated as of December 30, 2010 (as from time to time amended, the “ Note Purchase Agreement ”), between the Company and the respective Purchasers named therein and is entitled to the benefits thereof. Each holder of this Note will be deemed, by its acceptance hereof, to have (i) agreed to the confidentiality provisions set forth in Section 20 of the Note Purchase Agreement and (ii) made the representation set forth in Section 6.2 of the Note Purchase Agreement. Unless otherwise indicated, capitalized terms used in this Note shall have the respective meanings ascribed to such terms in the Note Purchase Agreement.

This Note is also subject to optional prepayment, in whole or from time to time in part, at the times and on the terms specified in the Note Purchase Agreement, but not otherwise.


Very truly yours,

CABOT OIL & GAS CORPORATION

By


Name:
Title:

Exhibit 4.4(a)

F ORM OF O PINION OF M ANAGING C OUNSEL FOR THE C OMPANY

(See attached)

Exhibit 4.4(b)

F ORM OF O PINION OF S PECIAL C OUNSEL FOR THE C OMPANY

(See attached)

Exhibit 4.4(c)

F ORM OF O PINION OF S PECIAL C OUNSEL TO THE P URCHASERS

(See attached)

Exhibit 10.1(a)

CABOT OIL & GAS CORPORATION

CHANGE IN CONTROL AGREEMENT

Confirmation that Certain Benefits no Longer Apply

WHEREAS, Cabot Oil & Gas Corporation, a Delaware corporation (the “Company”), and Dan O. Dinges, Scott C. Schroeder, Lisa A. Machesney, Abraham D. Garza, Jeffrey W. Hutton, Robert G. Drake, Phil Stalnaker, Matt Reid and Todd Roemer (“Executives”) each entered into an agreement (the “Change in Control Agreement”) providing that the Company will pay certain benefits in the event of a change in control of the Company, as described in the Change in Control Agreement; and

WHEREAS, the Company and each Executive previously entered into an individual letter agreement (the “SERP Agreement”) providing that the Company will pay certain supplemental benefits to such Executives, as described in the SERP Agreement; and

WHEREAS, effective as of December 9, 2010, the Company entered into an agreement (the “Agreement Concerning SERP”) with each Executive pursuant to which each Executive (i) acknowledged the Company’s right to terminate and liquidate the SERP Agreements and (ii) agreed that, in the event of the termination of the SERP Agreement, Section 1(p)(IV) of the Change in Control Agreement would no longer be effective without further action by the Executives; and

WHEREAS, effective as of October 26, 2010, the Company terminated the SERP Agreements.

NOW, THEREFORE, as of October 26, 2010, Section 1(p)(IV) of the Change in Control Agreement has no force of effect.

IN WITNESS WHEREOF, the Company has caused this confirmation to be executed by its duly authorized officer this 9 day of December, 2010, but effective as of October 26, 2010.


CABOT OIL & GAS CORPORATION

By:		/s/ Abraham D. Garza
		Name: Abraham D. Garza
		Title: V. P. Human Resources

Exhibit 10.2(a)

AGREEMENT CONCERNING SERP

WHEREAS, effective as of December 31, 2008, Cabot Oil & Gas Corporation (the “Company”) and (the “Executive”) entered into a letter of agreement (the “SERP Agreement”) providing that the Company would pay certain supplemental pension benefits (the (“SERP Benefits”) to Executive or, in the event of Executive’s death while in the service of the Company, Executive’s surviving spouse, if any, pursuant to the terms set forth in the SERP Agreement; and

WHEREAS, effective as of December 31, 2008, the Company and Executive entered into an agreement (the “Change in Control Agreement”) providing that the Company will pay certain benefits in the event of Executive’s termination in connection with a change in control of the Company, as described in the Change in Control Agreement; and

WHEREAS, effective as of December 31, 2008, the Company and Executive amended the SERP Agreement and the Change in Control Agreement in order to clarify their intent to comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended; and

WHEREAS, the Company and Executive now desire to enter into this agreement (the “Agreement”) to further clarify their understanding of the terms and conditions of the SERP Agreement and the Change in Control Agreement.

NOW, THEREFORE, the Company and Executive hereby agree as follows:

Executive acknowledges that (i) the Company has the right to freeze benefit accruals under, terminate and liquidate the SERP Agreement, and (ii) in the event of the termination of the SERP Agreement, the Company has the right to make such arrangements as the Company, in its sole discretion, shall deem appropriate for the payment of the SERP Benefits, including the right to determine the time and form applicable to any payment in liquidation of the SERP Benefits.

2.	Executive and the Company agree that, in the event of the termination of the SERP Agreement, without further action by Executive, Section 1(p)(IV) of such Change in Control Agreement shall be ineffective as a result of the termination of the SERP.

This Agreement is the parties’ final and complete expression of their agreement on the matters contained herein and supersedes any prior agreements, representations or undertakings of any kind, including, but not limited to, the provisions of the SERP Agreement or the Change in Control Agreement, as applicable.

4.	No provision of this Agreement may be amended unless such amendment is agreed to in writing and signed by both Executive and an authorized officer of the Company.

In the event that any provision or portion of this Agreement shall be determined to be invalid or unenforceable for any reason, in whole or in part, the remaining provisions of this Agreement shall be unaffected thereby and shall remain in full force and effect to the fullest extent permitted by law.

6.	This Agreement shall be governed by and construed and interpreted in accordance with the laws of the State of Texas without reference to principles of conflict of laws.

7.	This Agreement may be executed in one or more counterparts (including by facsimile), each of which shall be deemed to be an original but all of which together will constitute one and the same instrument.

IN WITNESS WHEREOF , the undersigned have executed this Agreement, effective as of this day of , 2010.


CABOT OIL & GAS CORPORATION


By:		[Name]


DATE


EXECUTIVE


DATE

Exhibit 10.7(a)

CABOT OIL & GAS CORPORATION

DEFERRED COMPENSATION PLAN

(As Amended and Restated Effective January 1, 2009)

First Amendment

WHEREAS, effective as of June 1, 1998, Cabot Oil & Gas Corporation, a Delaware corporation (the “Company”), established the Cabot Oil & Gas Corporation Deferred Compensation Plan, which was subsequently amended on several occasions, most recently in the form of an amendment and restatement that became effective as of January 1, 2009 (the “Plan”); and

WHEREAS, the Company desires to amend the Plan to clarify the terms and conditions of eligibility for participation in the Plan.

NOW, THEREFORE, having reserved the right to amend the Plan under Section 8.4 thereof, the Company hereby amends the Plan, effective as of October 1, 2010, as follows:

1. Section 1.2(q) of the Plan is hereby amended, in its entirety, to read as follows:

“1.2(q). ‘Eligible Employee’ shall mean members of the Company’s management group who are designated by the Company as eligible to participate in this Plan.”

2. Article II of the Plan is hereby amended by adding the following as the final sentence thereof:

“The Committee, in its sole discretion and on a Participant-by-Participant basis, may direct that a Participant shall not be permitted to make a Deferral Election under Article III of the Plan.”

IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by its duly authorized officer this 10th day of September, 2010, but effective as of October 1, 2010.

CABOT OIL & GAS CORPORATION

By: /s/ Abraham D. Garza

Name: Abraham D. Garza

Title: Vice President, Human Resources

Exhibit 10.7(b)

CABOT OIL & GAS CORPORATION

DEFERRED COMPENSATION PLAN

(As Amended and Restated Effective January 1, 2009)

Second Amendment

WHEREAS, effective as of June 1, 1998, Cabot Oil & Gas Corporation, a Delaware corporation (the “Company”), established the Cabot Oil & Gas Corporation Deferred Compensation Plan, which subsequently amended and restated effective as of January 1, 2009 (the “Plan”); and

WHEREAS, effective as of October 26, 2010, the Company terminated its letter agreements with certain executives providing for the contribution of certain supplemental pension amounts to the Plan upon the termination of the applicable executive’s employment (the “SERP Agreements”); and

WHEREAS, in connection with the termination of the SERP Agreements, the Company has directed the Committee to amend the Plan to provide for the termination and liquidation of the Company DB SERP Accounts currently maintained under the Plan.

NOW, THEREFORE, having reserved the right to amend the Plan under Section 8.4 thereof, the Committee hereby amends the Plan, effective as of October 26, 2010, as follows:

1. Section 4.2(c) of the Plan is hereby amended to read as follows:

“4.2(c) Effective as of the earlier of (i) the date of a Participant’s termination of employment with the Company or (ii) the Liquidation Date designated by the Committee in accordance with Section 6.1(e), the Committee shall credit to the Participant’s Company Contribution Account an amount equal to the actuarial present value of the Company DB SERP Contribution Amount to which such Participant would have been entitled under the terms of the supplemental employee retirement plan agreement in effect between the Company and the Participant as of September 29, 2010, if the Participant had terminated employment on September 30, 2010 (the ‘SERP Termination Date’), and shall allocate such credited amount among the Investment Subaccounts in accordance with the designation made by such Participant pursuant to Section 3.3(a); provided that, for purposes of this Section 4.2(c), ‘actuarial present value’ shall be determined in accordance with the then-applicable interest rate and mortality table (x) in effect under the Pension Plan or (y) if the Pension Plan is no longer in existence, last in effect under the Pension Plan; and”

2. Section 6.1 of the Plan is hereby amended by adding the following new section (e):

“6.1(e) Termination and Distribution of the Company DB SERP Account .

(i) No Company DB SERP Contributions attributable to services rendered by or compensation payable to a Participant after the SERP Termination Date shall be credited to a Participant’s Company DB SERP Contribution Account.

(ii) In accordance with the provisions set forth in Section 1.409A-3(j)(4)(ix)(C) of the Treasury Regulations with respect to the termination and liquidation of a deferred compensation plan, the Committee, in its sole discretion, shall designate a date (the ‘Liquidation Date’) between twelve and twenty-four months following the SERP Termination Date for the distribution of all Participants’ Company DB SERP Contribution Account.

(iii) A Participant shall receive a single lump-sum payment on the Liquidation Date in an amount equal to the balance, if any, of his or her Company DB SERP Contribution Account, determined as of the Liquidation Date.

(iv) Notwithstanding the foregoing, the terms of a Participant’s Deferral Election shall remain in effect with respect to (i) any amounts that would otherwise be distributed prior to the Liquidation Date, and (ii) any Company DB SERP Contribution Accounts that are eligible for grandfathered status in accordance with Section 409A.”

IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by its duly authorized officer effective as of October 26, 2010.

CABOT OIL & GAS CORPORATION

By: /s/ Abraham D. Garza

Name: Abraham D. Garza

Title: Vice President, Human Resources

Exhibit 10.22

CABOT OIL & GAS CORPORATION PENSION PLAN

(As Amended and Restated Effective September 30, 2010)

CABOT OIL & GAS CORPORATION PENSION PLAN

(As Amended and Restated Effective September 30, 2010)

I N D E X


		Page

ARTICLE I DEFINITIONS			2
1.1	Actuarial Equivalent		2
1.2	Actuary		3
1.3	Affiliate		3
1.4	Annuity Starting Date		3
1.5	Anniversary Date		3
1.6	Authorized Absence		4
1.7	Average Monthly Compensation		4
1.8	Board of Directors		4
1.9	Code		4
1.10	Committee		4
1.11	Company		4
1.12	Compensation		4
1.13	Disability		5
1.14	Effective Date		5
1.15	Employee		5
1.16	Employer		5
1.17	ERISA		5
1.18	Final Average Monthly Compensation		5
1.19	Grandfathered Employee		5
1.20	Hour(s) of Service		6
1.21	Joint Pensioner		6
1.22	Late Retirement Date		6
1.23	Leased Employee		6
1.24	Nongrandfathered Employee		6
1.25	Normal Retirement Date		7
1.26	Participant		7
1.27	Pension		7
1.28	Plan		7
1.29	Plan Year		7
1.30	Prior Plan		7
1.31	Prior Plan Participant		7
1.32	Retirement		7
1.33	Service		7
1.34	Spouse		7
1.35	Transferred Participant		7
1.36	Trustee		7
1.37	Trust Agreement		7
1.38	Trust Fund		8


ARTICLE II SERVICE, BREAK IN SERVICE AND SOCIAL SECURITY		9
2.1	Service	9
2.2	Authorized Absences	10
2.3	Break in Service	11
2.4	Participation and Service upon Reemployment Before a Break in Service	11
2.5	Participation and Service upon Reemployment After a Break in Service	11
2.6	Transfer of Employment	12
2.7	Special Eligibility and Vesting for Certain Employees	13
2.8	Automatic Grant of Service	13
2.9	Qualified Military Service	13

ARTICLE III PARTICIPATION IN THE PLAN		15
3.1	Employees Eligible to Participate	15
3.2	Employees Absent on Date of Eligibility	15

ARTICLE IV RETIREMENT ELIGIBILITY		16
4.1	Normal Retirement	16
4.2	Late Retirement	16
4.3	Early Retirement	16
4.4	Disability Retirement	16
4.5	Deferred Vested Retirement	17
4.6	Partial Vesting	17
4.7	Special Benefit Eligibility for Certain Employees	17

ARTICLE V AMOUNT, DURATION, COMMENCEMENT DATE, FREQUENCY AND LIMITATIONS OF RETIREMENT BENEFITS		18
5.1	Normal Retirement Pension	18
5.2	Late Retirement Pension	19
5.3	Early Retirement Pension	20
5.4	Disability Retirement Pension	20
5.5	Deferred Vested Retirement Pension	20
5.6	Automatic Option and Optional Pensions	21
5.7	Duration of Pensions	31
5.8	Payment of Small Benefits	32
5.9	Waiver of Waiting Period	32
5.10	Benefits after Reemployment	32
5.11	Minimum Date for Commencement of Benefits	33
5.12	Required Minimum Distributions	33
5.13	Direct Rollovers	34
5.14	Limitations on Benefit Accruals	36
5.15	Limitations on Accelerated Benefit Distributions	36

ARTICLE VI DEATH BENEFIT		38
6.1	Death While in Service but Prior to Commencement of Pension	38
6.2	Death After Retirement but Prior to Commencement of Pension	38
6.3	Death After Deferred Vested Retirement but Prior to Commencement of Pension	38


6.4	Definition of Spouse	38
6.5	Death Benefits Payable Under the Cabot Corporation Cash Balance Plan and Retirement Income Plan	39
6.6	Alternate Form of Pension Payment for Spouse	39

ARTICLE VII CLAIM PROCEDURES		40
7.1	Presenting Claims for Benefits	40
7.2	Claims Review Procedure	41
7.3	Disputed Benefits	45

ARTICLE VIII PLAN ADMINISTRATION		46
8.1	Allocation of Responsibility Among Fiduciaries for Plan and Trust Administration	46
8.2	Appointment of Committee	46
8.3	Records and Reports	47
8.4	Other Committee Powers and Duties	47
8.5	Rules and Decisions	47
8.6	Committee Procedures	48
8.7	Authorization of Benefit Payments	48
8.8	Payment of Expenses	48
8.9	Application and Forms for Pension	48
8.10	Indemnification of Committee	48
8.11	Annual Audit	49
8.12	Funding Policy	49
8.13	Allocation and Delegation of Committee Responsibilities	49

ARTICLE IX CONTRIBUTIONS TO THE PLAN		50
9.1	Participant Contributions	50
9.2	Employer Contributions	50
9.3	Discontinuance or Suspension of Contributions	50
9.4	Forfeitures Credited Against Employer’s Contributions	51

ARTICLE X AMENDMENT OF THE PLAN		52
10.1	Right to Amend Reserved	52
10.2	Limitations on Right to Amend	52
10.3	Form of Amendment	53
10.4	Merger of Plan with Another Pension Plan	53

ARTICLE XI THE TRUSTEE AND THE TRUST FUND		54
11.1	Trustee	54
11.2	Trust Agreement	54
11.3	Benefits Paid Solely from Trust Fund	54
11.4	Trust Fund Applicable Only to Payment of Benefits	54
11.5	Accounting by Trustee	54
11.6	Authorization to Protect Trustee	54
11.7	Exemption from Bond	54

iii


ARTICLE XII TERMINATION OF THE PLAN		55
12.1	Right to Terminate Reserved	55
12.2	Continuance with Successor Employer	55
12.3	Liquidation of Trust Fund	56
12.4	Distribution of Trust Fund	57
12.5	Residual Amounts	58
12.6	Limitations Imposed by Treasury Regulations upon Termination of Plan	58

ARTICLE XIII ADOPTION OF PLAN BY OTHER ORGANIZATIONS		60
13.1	Procedure for Adoption	60
13.2	Effect of Adoption	60
13.3	Separation of the Trust Fund	61
13.4	Voluntary Separation	61
13.5	Approval of Amendment	61

ARTICLE XIV MISCELLANEOUS		62
14.1	Interest on Deferred Payments	62
14.2	Plan Not an Employment Contract	62
14.3	Controlling Law	62
14.4	Invalidity of Particular Provisions	62
14.5	Non Alienability of Rights of Participants	62
14.6	Copy Available to Participants	62
14.7	Evidence Furnished Conclusive	63
14.8	Unclaimed Benefits	63
14.9	Name and Address Changes	63
14.10	Facility of Payment	63
14.11	Payments in Satisfaction of Claims of Participants	64
14.12	Headings for Convenience Only	64

ARTICLE XV LIMITATION ON BENEFITS		65
15.1	Limitations on Benefits	65

ARTICLE XVI TOP-HEAVY PLAN REQUIREMENTS		70
16.1	General Rule	70
16.2	Vesting Provisions	70
16.3	Minimum Benefit Provisions	70
16.4	Limitation on Compensation	71
16.5	Coordination With Other Plans	71
16.6	Distributions to Certain Key Employees	71
16.7	Determination of Top-Heavy Status	71

CABOT OIL & GAS CORPORATION PENSION PLAN

(As Amended and Restated Effective September 30, 2010)

Effective as of January 1, 1991, Cabot Oil & Gas Corporation, a Delaware corporation (the “Company”), established the Cabot Oil & Gas Corporation Pension Plan (the “Prior Plan”) for the benefit of its eligible employees and the eligible employees of its affiliates that adopted the Plan. The Prior Plan was subsequently amended by the First through Sixth Amendments thereto.

In connection with the establishment of the Prior Plan, the Company established the Cabot Oil & Gas Corporation Pension Plan Trust by agreement between the Company and NCNB Texas National Bank, a national banking association (the “Trust”). NCNB Texas National Bank was thereafter replaced by Bankers’ Trust and then Harris Trust and Savings Bank, respectively, as party to the Trust. Effective as of February 1, 2005, the Trust was amended and restated with Fidelity Management Trust Company as trustee thereunder. The Trust is intended to constitute a part of the Prior Plan and to continue in effect to form a part of this Plan.

Effective January 1, 2001, the Board of Directors of the Company authorized the amendment and restatement of the Prior Plan to incorporate the prior amendments, to incorporate changes required by certain legislative acts, and to make certain other changes.

Effective as of January 1, 2006, the Board of Directors of the Company authorized the amendment and restatement of the Prior Plan in order to incorporate all prior amendments thereto, including previously adopted good faith compliance amendments to reflect applicable law changes under the Economic Growth and Tax Relief Reconciliation Act of 2001 (the “Plan”) and to incorporate the applicable changes as required on the 2005 Cumulative List provided in Notice 2005-101.

Effective as of September 30, 2010, the Board of Directors of the Company authorized and directed that the Plan be terminated and further amended and restated in order to (i) incorporate all prior amendments to the Plan, (ii) comply with the required provisions in the Pension Protection Act of 2006, (iii) comply with such other requirements as may be necessary to maintain the Plan’s qualified status, including but not limited to, the Worker, Retiree, and Employer Recovery Act of 2008 and the Heroes Earnings Assistance and Relief Tax Act of 2008; and (iv) reflect the termination of the Plan effective as of September 30, 2010.

There shall be no termination and no gap or lapse in time or effect between the Plan as in effect on September 29, 2010, and this Plan, and the existence of a qualified pension plan shall be uninterrupted.

The Plan and Trust are intended to meet the requirements of Sections 401(a) and 501(a) of the Internal Revenue Code of 1986 and of the Employee Retirement Income Security Act of 1974, as either may be amended from time to time.

NOW, THEREFORE, the Company hereby amends, restates in its entirety and terminates the Cabot Oil & Gas Corporation Pension Plan, effective September 30, 2010, as follows:

ARTICLE I

DEFINITIONS

As used in this Plan the terms defined in this Article I shall have the meanings set forth herein, unless their context clearly indicates to the contrary:

1.1 Actuarial Equivalent . With respect to any specified annuity or benefit hereunder, another annuity or benefit, commencing at a different date or payable in a different form than the specified annuity or benefit, but which has the same present value as the specified annuity or benefit, when measured using the mortality and interest assumptions set forth below.

(a) Calculation of Payments in Forms Other Than a Lump Sum : The following provisions shall apply with respect to the calculation of amounts not payable in the form of a lump sum.

(i) For periods prior to October 1, 2004, the Plan shall use the following assumptions:

(1) “Applicable Interest Rate” shall mean an interest rate of eight percent (8%) per annum interest assumption; and

(2) “Applicable Mortality Table” shall mean the Unisex Mortality Table UP 1984.

(ii) For periods on or after October 1, 2004, the Plan shall use whichever of the following combinations yields the greater benefit:

(1) “Applicable Interest Rate” shall mean an interest rate of eight percent (8%) per annum interest assumption, and “Applicable Mortality Table” shall mean the Unisex Mortality Table UP 1984; or

(2) “Applicable Interest Rate” shall mean the annual rate of interest on thirty (30) year U.S. Treasury securities for the month of November immediately preceding the first day of the calendar year during which the Annuity Starting Date occurs and “Applicable Mortality Table” shall mean the 1994 Group Annuity Reserving Mortality Table.

(b) Calculation of Lump Sum Payments : The following provisions shall apply with respect to the calculation of any amounts payable as a lump sum.

(i) For periods prior to October 1, 2008, the Plan shall use the following assumptions:

(1) “Applicable Interest Rate” shall mean the annual rate of interest on thirty (30) year U.S. Treasury securities for the month of November immediately preceding the first day of the calendar year during which the Annuity Starting Date occurs; and

(2) “Applicable Mortality Table” shall mean the table prescribed by the Secretary of the Treasury pursuant to Section 417(e)(3) of the Code.

(ii) For periods on or after October 1, 2008, the following provisions shall apply:

(1) “Applicable Interest Rate” shall mean the annual rates of interest specified under Section 417(e)(3) for the month of November of the preceding year using applicable transition rates; and

(2) “Applicable Mortality Table” shall mean the mortality table specified under Section 417(e)(3) of the Code.

(c) Calculation for Benefits Payable Pursuant to Exhibit I . Solely for purposes of calculating the benefits set forth in Exhibit I, the Plan shall use whichever of the following yields the greater benefit:

(i) the calculation provided in Section 5.6(b)(ii); or

(ii) “Applicable Interest Rate” shall mean the annual rate of interest on thirty (30) year U.S. Treasury securities for the month of November immediately preceding the first day of the calendar year during which the Annuity Starting Date occurs and “Applicable Mortality Table” shall mean the 1994 Group Annuity Reserving Mortality Table.

1.2 Actuary : The independent actuary or firm of actuaries approved by the Joint Board for the Enrollment of Actuaries to perform actuarial services required under ERISA or regulations thereunder which has been appointed by the Company to make the actuarial computations required under the Plan.

1.3 Affiliate : A corporation or other trade or business which is not an Employer under this Plan but which, together with the Company, is “under common control” within the meaning of Code Section 414(b) or (c), as modified by Code Section 415(h); any organization (whether or not incorporated) which, together with the Company, is a member of an “affiliated service group” within the meaning of Code Section 414(m); and any other entity required to be aggregated with the Company pursuant to regulations under Code Section 414(o).

1.4 Annuity Starting Date : The applicable of the Participant’s Early Retirement Date, Normal Retirement Date or the first day of the month next following his actual termination of Service, if later, or in the case of a benefit not payable in the form of an annuity, the first day on which all events have occurred which entitle the Participant to such benefit.

1.5 Anniversary Date : October 1 of each year.

1.6 Authorized Absence : Any absence authorized by the Employer or an Affiliate under the Employer’s or Affiliate’s standard personnel practices, provided that all persons under similar circumstances are treated alike in the granting of such Authorized Leaves of Absence and provided further that the Participant returns within the period of authorized absence.

1.7 Average Monthly Compensation : The result obtained by dividing the total Compensation paid to an Employee during a considered period by the number of months, including fractional months, for which such Compensation was received. The considered period shall be the five (5) consecutive completed years of Service within the Employee’s last ten (10) consecutive completed years of Service which yield the highest average; provided, however, that if an Employee has fewer than five (5) consecutive completed years of Service for which Compensation was received, his considered period shall be all his years, including fractional years, for which Compensation was received. Any period of Service for which an Employee is not compensated shall be excluded from the above computation.

1.8 Board of Directors : The Board of Directors of Cabot Oil & Gas Corporation.

1.9 Code : The Internal Revenue Code of 1986, as amended.

1.10 Committee : The Administrative Committee appointed under and acting in accordance with the terms of the Plan.

1.11 Company : Cabot Oil & Gas Corporation, a Delaware corporation, and its successor or successors.

1.12 Compensation : The total nondeferred remuneration paid to an Employee by an Employer and, prior to January 1, 1991, by Cabot Corporation, for personal services which are rendered during the period considered as Service, as reported on the Participant’s Federal Income Tax Withholding Statement (Form W-2 or its subsequent equivalent) including salary, wages, overtime payments, annual, discretionary and sign-on bonuses, and any amounts by which an Employee’s normal remuneration is reduced pursuant to a voluntary salary reduction plan under Section 125 or 401(k) of the Code, but excluding any amounts contributed by or on behalf of an Employer to this Plan or any other employee benefit plan sponsored by the Employer, nondeductible moving expenses, disability pay (both short-term and long-term), severance pay (whether periodic or in a lump sum), any income arising from the exercise of a stock option or from the receipt of a restricted stock award, waiver benefits, taxable group term life insurance benefits, reimbursements, expense allowances, taxable fringe benefit payments, retention and relocation bonuses, any benefits payable or paid under the Cabot Oil & Gas Corporation Supplemental Employee Incentive Plan or any substantially similar plan established by the Employer, including but not limited to, the Cabot Oil & Gas Corporation Supplemental Employee Incentive Plan II, and deductible payments under Code Section 105(h). The Compensation of an Employee as reflected on the books and records of the Employer shall be conclusive.

Compensation earned for periods after September 30, 2010 shall not be considered for purposes of determining a Participant’s accrued benefit under the Plan.

Notwithstanding any other provision of the Plan to the contrary, the Compensation of each Employee taken into account under the Plan shall not exceed $220,000, as adjusted by the Commissioner for increases in the cost of living in accordance with Section 401(a)(17)(B) of the Internal Revenue Code; provided, however, that an Employee’s Compensation for determination periods before January 1, 2006 shall not exceed the applicable dollar limit previously in effect under the Plan in such prior determination periods. The cost-of-living adjustment in effect for a calendar year applies to any period, not exceeding 12 months, over which Compensation is determined (determination period) beginning in such calendar year. If a determination period consists of fewer than 12 months, the Compensation limit will be multiplied by a fraction, the numerator of which is the number of months in the determination period, and the denominator of which is 12. If Compensation for any prior determination period is taken into account in determining an Employee’s benefits accruing in the current Plan Year, the Compensation for that prior determination period is subject to the Compensation limit in effect for that prior determination period.

1.13 Disability : A physical or mental disability which prevents a Participant from engaging in any substantial gainful activity and which can be expected to result in death or to be of long continued and indefinite duration. The determination of whether a Participant has a Disability shall be determined according to the following: (i) for Participants who are also participants in the Cabot Oil & Gas Long Term Disability Plan (“Cabot LTD Plan”) at time of their claim of Disability, by the Cabot LTD Plan; or (ii) for Participants who do not participate in the Cabot LTD Plan at the time of their claim of Disability, by the Committee, upon the advice of competent physicians of the Committee’s selection.

1.14 Effective Date : September 30, 2010 unless otherwise specified herein.

1.15 Employee : Any person employed by an Employer.

1.16 Employer : The Company, and any other entity that shall adopt this Plan pursuant to the provisions of Article XIV hereof, and the successors, if any, to such entity.

1.17 ERISA : Public Law No. 93 406, the Employee Retirement Income Security Act of 1974, as amended from time to time.

1.18 Final Average Monthly Compensation : A Participant’s Average Monthly Compensation as determined immediately prior to his final termination of employment with all Employers or Affiliates.

1.19 Grandfathered Employee : An Employee who was a member of the Cabot Corporation Retirement Income Plan as of September 30, 1988 and had (a) 10 (ten) or more years of Vesting Service or (b) 5 (five) or more years of Vesting Service and his age plus years of Vesting Service equaled 50 (fifty) or more.

1.20 Hour(s) of Service : For purposes of determining eligibility and vesting, an Hour of Service is each hour during an applicable computation period for which an Employee is directly or indirectly paid, or entitled to payment, by an Employer or an Affiliate for the performance of duties or for any period of Authorized Leave of Absence. Moreover, an Hour of Service is each hour, not in excess of forty (40) hours per week, during any period of unpaid Authorized Leave of Absence with an Employer or an Affiliate. Such Hours of Service shall be credited to the Employee for the computation period in which such duties were performed or in which such Authorized Leave of Absence occurred. An Hour of Service also includes each hour, not credited above, for which back pay, irrespective of mitigation of damages, has been either awarded or agreed to by an Employer or an Affiliate. These Hours of Service shall be credited to the Employee for the computation period to which the award or agreement pertains rather than the computation period in which the award, agreement or payment is made. In determining an Employee’s total Hours of Service during a computation period, a fraction of an hour shall be deemed a full Hour of Service.

Instead of counting and crediting actual hours worked, for purposes of determining the number of Hours of Service to be credited to an Employee, an Employee may be credited with 190 Hours of Service for each calendar month during which he has earned one Hour of Service. For purposes of determining the number of Hours of Service to be credited for reasons other than the performance of duties and for purposes of determining to which computation period Hours of Service earned under any provision of this Plan are to be credited, the provisions of Department of Labor Regulation Section 2520.200(b)-2(b) and (c) are hereby incorporated by reference as if fully set forth herein.

Hours of Service will be credited for employment with other members of an affiliated service group (under Code Section 414(m)), a controlled group of corporations (under Code Section 414(b)), or a group of trades or businesses under common control (under Code Section 414(c)), of which the Company is a member. Hours of Service will also be credited for any individual considered an employee under Code Section 414(n). However, unless otherwise specifically provided, Hours of Service shall not be credited for employment with such an affiliated service group, a controlled group, or a group of trades or businesses prior to its becoming or after its ceasing to be a member of the Company’s affiliated service group, controlled group, or group of trades or businesses.

1.21 Joint Pensioner : The individual designated by a Participant who has elected an optional pension to receive Pension payments payable following the Participant’s death after Retirement, as provided in paragraph (b) of Section 5.6.

1.22 Late Retirement Date : The first day of the month coincident with or next following the Participant’s Retirement after his Normal Retirement Date.

1.23 Leased Employee : Each person who is not an employee of the Employer or an Affiliate but who performs services for the Employer or an Affiliate pursuant to a leasing agreement (oral or written) between the Employer or an Affiliate and any leasing organization, provided that such person has performed such services for the Employer or an Affiliate or for related persons (within the meaning of Section 144(a)(3) of the Code) on a substantially full time basis for a period of at least one year and such services are performed under primary direction or control by the Employer or an Affiliate. Notwithstanding the preceding sentence, the term “Leased Employee” shall not include any individual who is deemed to be an employee of the Employer or an Affiliate under Section 414(n)(5) of the Code.

1.24 Nongrandfathered Employee : Any Employee who is not a Grandfathered Employee.

1.25 Normal Retirement Date : The later of (i) the first day of the month coincident with or next following the Participant’s attainment of age sixty-five (65) and (ii) the completion of five (5) years of Service. Notwithstanding anything herein to the contrary, a Participant’s right to his accrued Normal Retirement Pension shall become fully vested and nonforfeitable upon his being in Service on or after the later to occur of his attainment of age 65 or the fifth anniversary of his becoming a Participant in the Plan.

1.26 Participant : Any Employee who has become and continues to be a participant in the Plan in accordance with its provisions. The term “Participant” shall also include Transferred Participants unless otherwise specifically excluded.

1.27 Pension : A series of monthly payments which are payable to a person entitled to receive benefits under the Plan.

1.28 Plan : The Cabot Oil & Gas Corporation Pension Plan, as amended and restated effective September 30, 2010, and as the same may be amended.

1.29 Plan Year : The fiscal year of the Plan beginning October 1 of each calendar year and ending September 30 of the following calendar year.

1.30 Prior Plan : The Cabot Oil & Gas Corporation Pension Plan as in effect on September 29, 2010.

1.31 Prior Plan Participant : Any person who is an Employee on September 30, 2010, and was, on September 29, 2010, included in and covered by the Prior Plan, or who is, on September 30, 2010 receiving or entitled to receive benefits under the Prior Plan.

1.32 Retirement : The termination of Service of a Participant after he has fulfilled all requirements for an immediate Pension hereunder. Retirement shall be considered as commencing on the day immediately following a Participant’s last day of Service.

1.33 Service : A Participant’s period of employment or deemed employment determined in accordance with Article II.

1.34 Spouse : The person to whom a Participant is legally married.

1.35 Transferred Participant : An Employee shall be deemed a Transferred Participant during any period in which he is or was employed by an Affiliate or by an Employer in an employment classification not covered by this Plan.

1.36 Trustee : The Trustee at any time acting under the Trust Agreement.

1.37 Trust Agreement : The Trust Agreement provided for in Section 11.2 hereof, and as the same may be amended.

1.38 Trust Fund : The assets held by the Trustee under the Trust Agreement for the benefit of the Participants of the Prior Plan and this Plan, together with all income, profits and increments thereon.

Words used in this Plan and in the Trust Agreement in the singular shall include the plural and in the plural the singular, and the gender of words used shall be construed to include whichever gender may be appropriate under any particular circumstances.

ARTICLE II

SERVICE, BREAK IN SERVICE AND SOCIAL SECURITY

2.1 Service :

(a) Eligibility and Vesting : For purposes of determining Eligibility Service and Vesting Service, an Employee shall accrue a year of Service for each Plan Year in which he has 1,000 or more Hours of Service subject to the Break in Service provisions of Sections 2.3, 2.4 and 2.5. Solely for eligibility purposes, an Employee’s initial year of Eligibility Service shall be the twelve (12) consecutive months beginning with his employment commencement date (or his reemployment commencement date if he is reemployed after a one-year Break in Service). If such Employee fails to complete 1,000 or more Hours of Service during such twelve (12) consecutive months, subsequent years of Eligibility Service shall be Plan Years beginning with the Plan Year which includes the anniversary of the Employee’s employment commencement date. Solely for vesting purposes, an Employee shall accrue a year of Vesting Service for each twelve (12) consecutive months beginning with the employment commencement date (or his reemployment commencement date if he is reemployed after a one year Break in Service) during which the Employee completes at least 1,000 Hours of Service. An Employee’s or Participant’s Service shall commence (or recommence) on the date such Employee or Participant first performs an Hour of Service. No Employee shall be credited with Eligibility Service or Vesting Service for periods after September 30, 2010.

Solely for purposes of determining whether a Break in Service has occurred for purposes of determining Eligibility Service and Vesting, an individual who is absent from work for maternity or paternity reasons shall receive credit for the Hours of Service which would otherwise have been credited to such individual but for such absence or, in any case in which such hours cannot be determined, eight (8) Hours of Service per day of such absence except that the total number of hours treated as Hours of Service shall not exceed 501 hours. For purposes of this paragraph, an absence from work for maternity or paternity reasons means an absence (a) by reason of the pregnancy of the individual, (b) by reason of a birth of a child of the individual, (c) by reason of the placement of a child with the individual in connection with the adoption of the child by such individual or (d) for purposes of caring for such child for a period beginning immediately following such birth or placement. The Hours of Service credited under this paragraph shall be credited (a) in the computation period in which the absence begins if the crediting is necessary to prevent a Break in Service in that period or (b) in all other cases, in the following computation period.

(b) Benefit Service : For purposes of determining Benefit Service, an Employee shall be credited with Service for all years, months and days of active employment as an Employee or a Participant, plus periods included under Sections 2.2, 2.3, 2.4 or 2.5. Benefit Service shall also include a Participant’s years of Service with Cabot Corporation prior to January 1, 1991. If the Participant completes less than a full year of Service during the Plan Year, he will be given credit for one twelfth (1/12) of a year of Benefit Service for each month completed during the Plan Year. No Employee shall be credited with Benefit Service for periods after September 30, 2010.

An Employee’s or Participant’s Service shall commence (or recommence) on the date such Employee or Participant first performs an Hour of Service. A period of Service of an Employee or Participant shall terminate upon the first to occur of (i) his retirement or death, (ii) his quitting or discharge other than during or upon expiration of an Authorized Absence, (iii) his quitting or discharge during such an Authorized Absence, (iv) his deemed date of termination of employment pursuant to his failure to return to active employment upon the expiration of an Authorized Absence or (v) one (1) year from the date the Employee is absent from active employment for any reason other than Retirement, quit, discharge, Authorized Absence or death. For purposes of clause (iv) immediately above, a Participant’s deemed date of termination of employment shall be the earlier of (a) the expiration date of such Authorized Absence and (b) one (1) year from the date such Authorized Absence commenced. In the event a Participant’s employment is terminated because of Disability, such Participant’s Service shall continue for the entire period from the date of such Disability to the earlier of (i) the Participant’s date of recovery or death or (ii) the Participant’s Normal Retirement Date. Unless a period of Service can be disregarded under the Break in Service provisions of Sections 2.3, 2.4 or 2.5 hereof, all periods of Service shall be aggregated so that a one year period of Service shall be completed as of the date an Employee or Participant completes three hundred sixty-five (365) days of Service.

Solely for purposes of determining whether a Break in Service, as defined in Section 2.3, for purposes of determining Benefit Service has occurred, the Service of an individual who is absent from Service beyond the first anniversary of the first date of absence for maternity or paternity reasons shall not terminate until the expiration of two (2) years after the first date such absence commenced. For purposes of this paragraph, an absence from work for maternity or paternity reasons means an absence (a) by reason of the pregnancy of the individual, (b) by reason of the birth of a child of the individual, (c) by reason of the placement of a child with the individual in connection with the adoption of such child by such individual or (d) for purposes of caring for such child for a period beginning immediately following such birth or placement.

2.2 Authorized Absences : Service shall include and shall not be interrupted by Authorized Absences. The Employee or Participant shall be credited with Service during a period of Authorized Absence, as described below. Authorized Absences shall include the following periods of absence:

(a) Absence due to accident or sickness so long as the Employee or Participant is continued on the employment rolls of the Employer or Affiliate and remains eligible to return to work upon his recovery;

(b) Absence due to membership in the Armed Forces of the United States (but if such absence is not pursuant to orders issued by the Armed Forces of the United States, only if with the consent of the Employer) but only if, and then only to the extent that, applicable federal law requires such military service to be counted as Service hereunder and only if the Employee or Participant has complied with all prerequisites of such federal law; and

(c) Absence due to an authorized leave of absence granted by an Employer or Affiliate pursuant to established practices applied in a consistent and non discriminatory manner, in order that all employees under similar circumstances are treated alike, provided that each such Employee or Participant shall, prior to the expiration of such leave, apply for reinstatement in the employment of the Employer or Affiliate.

2.3 Break in Service : An Employee shall incur a one-year Break in Service in any Plan Year during which he does not complete more than 500 Hours of Service. In the event an Employee or Participant recommences Service with an Employer or an Affiliate prior to incurring a Break in Service, the period of his interim absence shall constitute Service for purposes of the Plan.

2.4 Participation and Service upon Reemployment Before a Break in Service : Upon the reemployment before a Break in Service of any person who had previously been employed by an Employer or Affiliate, the following rules shall apply. If the reemployed person was not a Participant during his prior period of Service, he must meet the requirements of Section 3.1 for participation in the Plan as if he were a new Employee; provided, however, for the purpose of determining whether an Employee meets the requirements of Section 3.1, Hours of Service during his prior period of employment and the period of his interim absence shall be recognized. If the reemployed person was a Participant in the Plan during his prior period of Service, he shall be entitled to recommence participation as of the date of his reemployment, all years of Vesting Service and Benefit Service attributable to his prior period of Service shall be reinstated as of the date of his reemployment and the period of his interim absence shall constitute Vesting Service but not Benefit Service.

2.5 Participation and Service upon Reemployment After a Break in Service : Upon the reemployment after a Break in Service of any person who had previously been employed by an Employer or Affiliate, the following rules shall apply in determining his eligibility for participation and his Service:

(a) Eligibility Service : If an Employee was not a Participant during his pre-break Service, he must meet the requirements of Section 3.1 for participation in the Plan as if he were a new Employee and Hours of Service during his prior period of employment shall be considered in determining whether he meets these requirements. If the reemployed person was a Participant during his prior period of employment, he shall be entitled to recommence participation as of the date of his reemployment, provided he completes one year of Service after the date of his reemployment.

(b) Vesting and Benefit Service : If the reemployed person was not a Participant during his prior period of employment or was a Participant whose prior Service terminated without entitlement to a Pension, any Vesting Service and Benefit Service attributable to his prior period of employment shall be reinstated as of the date of his recommencement of participation only if the number of consecutive one year Breaks in Service is less than the greater of five (5) or the aggregate number of his years of pre break Service. If the re employed person was a Participant whose pre break Service terminated with entitlement to a Pension, all years of Vesting Service and Benefit Service attributable to his prior period of employment shall be reinstated upon his recommencing participation in the Plan.

2.6 Transfer of Employment : In the event that a Participant is transferred from an employment classification with an Employer that is covered by this Plan to (i) an employment classification with the same Employer or with another Employer that is not covered by this Plan or (ii) employment with an Affiliate, such Participant shall retain all the benefits accrued to him under this Plan prior to the date of transfer and shall retain such benefits until his subsequent retirement or other termination of employment with an Employer or any Affiliate. Such Participant shall also continue to accrue Vesting Service for all periods of employment with an Employer not covered by this Plan or with an Affiliate.

In the event that an individual is transferred from (i) an employment classification with an Employer that is not covered by this Plan to an employment classification with the same Employer or another Employer that is covered by this Plan or (ii) employment with an Affiliate to an employment classification with an Employer that is covered by this Plan, such individual shall retain his credited service and all benefits accrued to him under the retirement plan, if any, covering his employment prior to that date of the transfer; provided, however, that for purposes of this Plan such employment prior to the date of transfer shall not constitute Benefit Service (except as provided in Section 2.1(b) hereof) and shall be considered only for purposes of determining his eligibility to participate in, and his vested interest under, this Plan. After the date of such transfer such individual shall accrue the benefits specified under this Plan provided he is otherwise eligible therefor.

It is intended by this Section 2.6 to credit an individual or Participant with Service for eligibility purposes, if applicable, and with Vesting Service for vesting purposes during all periods of employment while in a Transferred Participant status and all such Service and such Vesting Service shall be determined as though such employment while in a Transferred Participant status were employment by an Employer covered by this Plan.

All benefits accrued under this Plan and under any other retirement plan covering Employees of an Employer or of an Affiliate that are payable to a Participant shall be paid from the funding medium of the plan under which the Participant was last an active member if permitted under such plan; provided, however, that the funding medium for such plan shall be reimbursed by the funding medium of the other plan or plans for such benefits paid which were not accrued under the plan making the payments. Such amounts to be reimbursed shall be agreed upon by the plan administrator for each such plan, and each such plan administrator shall authorize the appropriate trustee to pay or receive the agreed upon amount.

Notwithstanding any other provision in this Plan to the contrary, there shall be no duplication of Pensions payable under this Plan and pensions or other retirement benefits payable under any other defined benefit pension plan of an Employer or Affiliate, and any pension or retirement benefit payable to any Participant under any other defined benefit pension plan of an Employer or Affiliate based on a period of Service for which Benefit Service is given under this Plan shall be deducted from the total Pension otherwise payable to such Participant under this Plan. A transfer of employment of a Participant (excluding a Transferred Participant) from one Employer to another Employer in an employment classification covered by this Plan shall not affect a Participant’s Eligibility Service, Vesting Service or Benefit Service. Unless specifically provided in this Plan to the contrary, Service shall not be credited for employment with an affiliated service group, controlled group or group of trades or businesses prior to its becoming or after its ceasing to be a member of the Company’s affiliated service group, controlled group or group of trades or businesses or for any period during which the Employer or Affiliate does not maintain this Plan.

2.7 Special Eligibility and Vesting for Certain Employees : Effective on the dates provided below, the employees acquired as a result of the acquisition of certain assets of or merger with the following companies (the “Acquired Companies”) shall automatically become Participants of this Plan subject to the eligibility requirements under Article III. Any period of employment immediately prior to the effective date of the acquisition with an Acquired Company or an affiliate of an Acquired Company shall be considered for purposes of determining a Participant’s Eligibility Service and Vesting Service under this Plan to the extent such employment otherwise qualifies under the relevant provisions of the Plan, but in no event shall any such period of employment constitute Benefit Service under this Plan:


Acquired Company		Effective Date
Doran & Associates, Inc.		March 1, 1989
Emax Oil Company		October 1, 1993
Washington Energy Resources Company		May 3, 1994
Oryx Energy Company		December 30, 1998
Cody Energy LLC		August 17, 2001

2.8 Automatic Grant of Service : All employees who become employed by the Company as a result of an acquisition of or merger with an employer not affiliated with the Company (“Acquired Company”) shall be credited with service with the Acquired Company immediately prior to the acquisition for purposes of eligibility and vesting hereunder.

2.9 Qualified Military Service :

(a) Notwithstanding any provisions of this Plan to the contrary, contributions, benefits and service credit with respect to qualified military service will be provided in accordance with Section 414(u) of the Code. Specifically, as required by Section 414(u)(8) of the Code, the Participant will be treated as not having incurred a Break in Service because of his period of Qualified Military Service, and the Participant’s Qualified Military Service will be treated as Service for purposes of calculating Vesting Service and Benefit Service.

(b) If Participant’s death occurs on or after January 1, 2007, while performing Qualified Military Service, then, provided such Participant was entitled to reemployment rights with respect to the Employer under Code Section 414(u) as of the date of his death, the Participant’s Beneficiary or Beneficiaries shall be entitled to any benefits (other than benefit accruals relating to the period of Qualified Military Service) that would have been provided under the Plan if the Participant had resumed and then terminated his Service on account of death, in compliance with Code Section 401(a)(37) and the Treasury regulations and guidance issued by the Internal Revenue Service thereunder.

(c) If an individual is paid remuneration by an Employer after December 31, 2008 that constitutes a “differential wage payment” within the meaning of Code Section 3401(h)(2), the differential wage payment shall not be treated as Compensation.

(d) No Participant or Beneficiary shall be entitled to any continued benefit accruals under Code Section 414(u)(9) (as enacted under section 104(b) of the Heroes Earnings Assistance and Relief Act of 2008) by reason of incurring a death or disability during a period of Qualified Military Service.

ARTICLE III

PARTICIPATION IN THE PLAN

3.1 Employees Eligible to Participate : Each Prior Plan Participant shall become a Participant in the Plan as of the Effective Date. Each other Employee shall participate in the Plan commencing on the first day of the month coincident with or next following his completion of one year of Eligibility Service. No Employee shall commence or recommence participation in the Plan after September 30, 2010.

Notwithstanding anything to the contrary in this Plan, the following Employees shall not be eligible to participate in the Plan: (i) Leased Employees, (ii) employees covered by a collective bargaining agreement between employee representatives and the Employer, if there is evidence that retirement benefits were the subject of good faith bargaining between such employee representatives and the Employer and such collective bargaining agreement does not expressly provide for coverage of such employees hereunder, (iii) persons who are non-resident aliens and who receive no earned income (within the meaning of Code Section 911) from the Employer which constitutes income from sources within the United States (within the meaning of Code Section 861), and (iv) persons who are utility employees (as herein defined). For purposes of this Plan, a utility employee is an employee who is hired in a utility position. A utility position is (i) a position which is expected by the respective Employer or Affiliate to be of limited duration or (ii) for a particular project upon the conclusion of which the employee is expected by the respective Employer or Affiliate to be terminated.

3.2 Employees Absent on Date of Eligibility : Any Employee who is on an Authorized Absence on his eligibility date shall automatically become a Participant as of such eligibility date.

ARTICLE IV

RETIREMENT ELIGIBILITY

4.1 Normal Retirement : A Participant who retires on his Normal Retirement Date shall be entitled to receive the Normal Retirement Pension provided for in Section 5.1 commencing on his Annuity Starting Date. Each Participant who is an Employee on September 30, 2010, shall be fully vested in his accrued benefit under the Plan as of such date.

4.2 Late Retirement : A Participant who remains in the active Service of the Employer beyond his Normal Retirement Date and who retires on his Late Retirement Date shall be entitled to receive the Late Retirement Pension provided for in Section 5.2 commencing on his Annuity Starting Date.

4.3 Early Retirement : A Participant’s Early Retirement Date is the first day of the month following his termination of Service after the Participant has completed at least ten (10) years of Vesting Service and has attained age fifty-five (55) but not age sixty-five (65). A Participant who retires on an Early Retirement Date shall be entitled to receive the Early Retirement Pension provided for in Section 5.3 commencing on his Annuity Starting Date.

4.4 Disability Retirement : A Participant who shall terminate his Service because of Disability after completion of five (5) years of Vesting Service but prior to his Normal Retirement Date, and who shall be eligible for and receive disability benefits under the Federal Social Security Act (after the waiting period required in such Act) continuously until he attains age sixty-five (65), shall be entitled to receive the Disability Retirement Pension provided for in Section 5.4; provided, however, that any Employee who is entitled to an Early Retirement Pension and who has elected to receive payment of such Early Retirement Pension prior to his Normal Retirement Date under Section 5.3 hereof shall not be eligible for a Disability Retirement Pension.

The Disability of any Participant shall be determined by the Committee in accordance with uniform principles consistently applied upon the basis of such medical or other evidence as the Committee deems necessary or desirable. Disability shall be considered to have ended if, prior to his Normal Retirement Date, the Participant (i) engages in any substantial gainful employment, except for such employment as is found by the Committee to be for the primary purpose of rehabilitation or not incompatible with a finding of total and permanent disability, (ii) has sufficiently recovered, based on a medical examination by a physician of the Committee’s selection, to be able to engage in regular full time employment with any employer, or (iii) refuses to undergo any medical examination requested by the Committee, provided that a medical examination shall not be required more frequently than twice in any calendar year.

If the Disability of a Participant is considered to have ended as described above prior to his attaining age sixty-five (65) and he is not reemployed by the Employer, his Accrued Pension (as described in Section 5.1) payable at age sixty-five (65) will be recalculated to reflect Service only to the date of recovery.

If the Disability of a Participant is considered to have ended as described above prior to his attaining age sixty-five (65) and he is reemployed by the Employer, he will immediately become a Participant and will be granted Benefit Service for the period of Disability.

4.5 Deferred Vested Retirement : A Participant who has completed five (5) years of Vesting Service, whose Service is terminated for any reason other than Disability, Normal, Late or Early Retirement, or death, shall be entitled to receive a Deferred Vested Retirement Pension as provided for in Section 5.5.

Each Participant whose Service is terminated other than by Disability, Normal, Late or Early Retirement or death prior to the time he has met the requirements for a Deferred Vested Retirement Pension set forth above in this Section 4.5 shall not be entitled to any benefit under this Plan whatsoever. A Participant who terminates Service without entitlement to a benefit shall be deemed to have received the full amount of his benefit pursuant to Section 1.411(a) 7(d) of the Treasury regulations.

If a terminated Participant is subsequently reemployed by the Employer, any Accrued Pension amounts received as of and during his termination shall become a permanent reduction to any Accrued Pension payable under the Plan upon any subsequent termination, Retirement, Disability or death.

4.6 Partial Vesting : Any Employee or Participant who, as of December 31, 1990, was partially vested under the Cabot Corporation Cash Balance Plan will be vested in his benefits under this Plan to the same extent he would have been vested under the Cabot Corporation Cash Balance Plan, except that any Employee or Participant who completes a total of five (5) years of Vesting Service shall be one hundred percent (100%) vested in his benefits under this Plan.

4.7 Special Benefit Eligibility for Certain Employees : Certain Employees of the Company who attain age 52 on or before March 31, 1995 and who, on or before October 1, 1994, had two or more years of Vesting Service, as determined under Section 2.1 of the Plan, will be eligible to participate in the Cabot Oil & Gas Corporation “3 + 3” Program (the “Program”). An eligible Employee who (i) receives a letter on or before February 28, 1995 informing the Employee of his eligibility for the Program, (ii) who makes an election to participate in the Program within 30 days after receiving such letter and (iii) who does not revoke the election during such 30 day period will terminate Service effective April 1, 1995 unless requested by the Company to continue employment for an additional period of time. Upon finalizing such irrevocable election, each Program participant shall be entitled, as of March 31, 1995, to have three years added to his age for purposes of determining the amount of any applicable reduction for commencement of payments and eligibility for early retirement, three additional years credited to his Benefit Service and Vesting Service as of such date and, solely for purposes of calculating the participant’s Normal Retirement Pension under Section 5.1 of this Plan, the Program participant’s Compensation as of December 31, 1994 applied as the Program participant’s Compensation for such additional years of Service.

ARTICLE V

AMOUNT, DURATION, COMMENCEMENT DATE,

FREQUENCY AND LIMITATIONS OF RETIREMENT BENEFITS

5.1 Normal Retirement Pension : A Participant who terminates his Service on or after the Effective Date and after qualifying for a Normal Retirement Pension under Section 4.1 shall be entitled to receive from the Trust Fund a Normal Retirement Pension for his lifetime, which shall be in an amount equal to the applicable of the following:

(a) Each Participant who is a Nongrandfathered Employee shall receive a monthly amount equal to the sum of the following:

(i) 1.1% of the Participant’s Final Average Monthly Compensation multiplied by the number of full and fractional years of Benefit Service earned; plus

(ii) 0.4% of the Participant’s Final Average Monthly Compensation in excess of 1/12 of the Participant’s Social Security Covered Compensation (as hereinafter defined) multiplied by the number of full and fractional years of Benefit Service earned (up to 35 years); minus

(iii) The monthly benefit payable at age 65 under the Cabot Corporation Cash Balance Plan as determined in Section 5.6(b)(ii), and the accrued benefit earned under the Cabot Corporation Retirement Income Plan as of September 30, 1988 as guaranteed by the Prudential Insurance Company (as detailed in Exhibit II, a copy of which is attached hereto and is hereby incorporated into this Plan).

(b) Each Participant who is a Grandfathered Employee shall receive a monthly amount equal to the sum of the following:

(i) 1.28% of Final Average Monthly Compensation multiplied by the full and fractional number of years of Benefit Service, plus

(ii) 0.4% of Final Average Monthly Compensation in excess of 1/12 of the Participant’s Social Security Covered Compensation (as hereinafter defined) multiplied by the number of full and fractional years of Benefit Service earned (up to 35 years), minus

A Participant’s “Social Security Covered Compensation” for a calendar year is the average (without indexing) of the taxable wage bases in effect for each calendar year during the 35 year period ending with the last day of the calendar year in which the Participant attains (or will attain) his Social Security Retirement Age, as defined in Code Section 415(b)(8). In determining a Participant’s Social Security Covered Compensation for a calendar year, the taxable wage base for the current calendar year and any subsequent calendar year shall be assumed to be the same taxable wage base as in effect as of the beginning of the calendar year for which the determination is being made. A Participant’s Social Security Covered Compensation for a calendar year after the 35 year period described in this Section 5.1 is the Participant’s Social Security Covered Compensation for the calendar year during which the Participant attained his Social Security Retirement Age. A Participant’s Social Security Covered Compensation for a calendar year before the 35 year period described in this Section 5.1 is the taxable wage base in effect as of the beginning of the calendar year. A Participant’s Social Security Covered Compensation shall be automatically adjusted for each calendar year.

Unless otherwise provided under the Plan, each Section 401(a)(17) Employee’s accrued benefit under this Plan will be the greater of the accrued benefit determined for the employee under (a) or (b) below:

(a) the Employee’s accrued benefit determined with respect to the benefit formula applicable for the Plan Year beginning on or after January 1, 1994, as applied to the Employee’s total years of Service taken into account under the Plan for the purposes of benefit accruals; or

(b) the sum of:

(i) the Employee’s accrued benefit as of the last day of the last Plan Year beginning before January 1, 1994 frozen in accordance with Section 1.401(a)(4) 13 of the regulations; and

(ii) the Employee’s accrued benefit determined under the benefit formula applicable for the Plan Year beginning on or after January 1, 1994, as applied to the Employee’s years of Service credited to the employee for Plan Years beginning on or after January 1, 1994 for purposes of benefit accruals.

A Section 401(a)(17) Employee means an employee whose current accrued benefit as of a date on or after the first day of the first Plan Year beginning on or after January 1, 1994 is based on Compensation for a year beginning prior to the first day of the first Plan Year beginning on or after January 1, 1994 that exceeded $150,000.

Unless the Participant elects otherwise in writing, the distribution of his Pension shall begin no later than the 60th day after the latest of the close of the Plan Year in which (i) the Participant attains age 65, (ii) occurs the 10th anniversary of the Plan Year in which the Participant commences participation in the Plan, or (iii) the Participant terminates Service.

5.2 Late Retirement Pension : A Participant who meets the requirements for a Late Retirement Pension and retires on a Late Retirement Date shall receive for his lifetime a monthly amount commencing on his Annuity Starting Date equal to his accrued Normal Retirement Pension at his Late Retirement Date. Notwithstanding any other provisions of this Plan to the contrary, if a Participant attains age 70 ¹ / 2 prior to his Late Retirement Date, his Late Retirement Pension shall commence no later than April 1 of the calendar year following the calendar year during which such Participant attains age 70 ¹ / 2 , whether or not such Participant has retired or otherwise terminated Service.

5.3 Early Retirement Pension : Any Participant who retires after satisfying the requirements for Early Retirement set forth in Section 4.3 shall be entitled to receive an Early Retirement Pension commencing at his Normal Retirement Date in a monthly amount equal to his accrued Normal Retirement Pension at his Early Retirement Date. The amount of his accrued Normal Retirement Pension shall be equal to the product of (a) the Normal Retirement Pension he would have received at Normal Retirement Age (determined pursuant to Section 5.1(a)(i) and (a)(ii) or Section 5.1(b)(i) and (b)(ii), whichever is applicable) using his Final Monthly Average Compensation and Covered Compensation as of his Early Retirement Date and the Benefit Service projected to his Normal Retirement Date, multiplied by (b) a fraction the numerator of which is his Benefit Service as of his Early Retirement Date and the denominator of which is his projected Benefit Service at his Normal Retirement Date. Such amount shall then be reduced by the offsets described in Section 5.1(a)(iii) or 5.1(b)(iii), whichever is applicable. If the Participant entitled to an Early Retirement Pension requests, such Participant shall receive a Pension, commencing on the first day of any month following his Retirement on or after his Early Retirement Date and preceding his Normal Retirement Date, in a monthly amount computed under the above provisions of this Section 5.3 but reduced by one-quarter of one percent (0.25%) per month for each month by which the starting date of such Pension precedes the Participant’s attainment of age sixty-two (62). The Early Retirement Pension is payable monthly for the Participant’s life, except as may be provided in Section 5.6.

5.4 Disability Retirement Pension : Any Participant who retires because of Disability and who satisfies the requirements for Disability Retirement set forth in Section 4.4 shall be entitled to receive a Disability Retirement Pension, in lieu of any other Pension payable under this Article V, commencing at his Normal Retirement Date, in an amount equal to the benefit the Participant would have earned had he remained in Service calculated with Benefit Service projected to his Normal Retirement Date but based on the Participant’s Compensation in effect on the date of Disability. If a Participant subsequently satisfies the requirements of Section 4.3 based on Service accrued during the period of his Disability, he may request early commencement of his Disability Retirement Pension as provided in Section 5.3. Such Disability Retirement Pension shall be payable monthly for the Participant’s life, except as may be provided in Section 5.6.

5.5 Deferred Vested Retirement Pension : Any Participant who terminates Service after meeting the requirements for Deferred Vested Retirement set forth in Section 4.5 shall be entitled to receive a Deferred Vested Retirement Pension commencing on his Normal Retirement Date and payable monthly for the Participant’s life, except as may be provided in Section 5.6.

Such Deferred Vested Retirement Pension shall commence on the Participant’s Normal Retirement Date unless such Participant duly elects to receive a reduced Deferred Vested Retirement Pension commencing on the first day of any month following the month in which he attains age 55. Such Deferred Vested Retirement Pension will be determined in the same manner as under Section 5.3 based on such Participant’s date of termination, except the benefit will be reduced by one half of one percent (0.50%) per month for each month by which such commencement date precedes age 65. Notwithstanding the foregoing, effective as of September 30, 2010, such Deferred Vested Retirement Pension will be determined in the same manner as under Section 5.3 based on the date on which payment of such benefit commences , except the benefit will be reduced by (i) one-quarter of one percent (0.25%) per month for each month by which such commencement date precedes age 62 but not age 55. If the single sum present value of the Participant’s Deferred Vested Retirement Pension determined as of the Participant’s date of termination is not more than $1,000, the Committee shall pay such single sum present value to the Participant in a lump sum in lieu of any other benefit payable hereunder, unless the Participant elects to have such amount paid directly to an eligible retirement plan in the form of a direct rollover.

Effective October 1, 2004, any Participant who is eligible to receive a Deferred Vested Retirement Pension which has a single sum present value that does not exceed $50,000 as of October 1, 2004, shall be permitted to elect to receive his Deferred Vested Retirement Pension in the form of an immediate lump sum distribution in complete satisfaction of the Plan’s obligations under Article V of the Plan. Such election must occur within 60 days of receipt by the Participant of the applicable election notice.

A Participant who terminated Service prior to February 18, 2010 with entitlement to a Deferred Vested Retirement Pension which, as of such date, has not begun to be distributed may elect to receive his Deferred Vested Retirement Pension in an immediate lump-sum distribution in complete satisfaction of the Plan’s obligations under this Article V; provided, however, that such election (i) is submitted to the Committee in writing on or before the 60th day following the date on which the Committee provides notice of such election right to the Participant and (ii) complies with any additional procedures established by the Committee, in its sole discretion.

Notwithstanding the foregoing, any Participant who, as of September 30, 2010, is entitled to receive a Pension under the terms of this Article V but has not had an Annuity Starting Date may elect an immediate lump-sum distribution in complete satisfaction of the Plan’s obligations under this Article V; provided, however, that such election (i) is submitted to the Committee in writing on or before the 60th day following the date on which the Committee provides notice of such election right to the Participant and (ii) complies with any additional procedures established by the Committee, in its sole discretion.

5.6 Automatic Option and Optional Pensions : A written explanation of the terms and conditions of the optional forms of payment under this Section 5.6, their relative values and the consequences of failing to defer receipt of the distribution will be furnished to a Participant no less than 30 days and no more than 180 days prior to the date when he would first become eligible to commence receiving a Pension hereunder. Further, a written explanation of the terms and conditions of the Automatic Option and the effect of refusing it will be furnished to the Participant no less than 30 days and no more than 180 days prior to a Participant’s Annuity Starting Date. However, the Plan may permit a Participant to elect (with any applicable spousal consent) to waive any requirement that the written explanation be provided at least 30 days before the Annuity Starting Date if the distribution commences more than 7 days after such explanation is provided.

(a) Automatic Option : A Participant who (i) retires on a Normal, Early or Late Retirement Date or who terminates Service after meeting the requirements for a Deferred Vested Pension or who terminates Service because of Disability and (ii) is legally married as of his Annuity Starting Date, shall receive, in lieu of the Pension to which he is otherwise entitled, the Automatic Option which is the Actuarial Equivalent of his Pension otherwise payable, unless he shall have theretofore elected in writing, with the written consent of his Spouse, if any, not to receive such Automatic Option after having received a written explanation of the terms and conditions of the Automatic Option and the effect of an election not to receive such Automatic Option but to instead receive his Pension as otherwise payable hereunder. As used in this paragraph (a), “Automatic Option” means for a Participant who is married on his Annuity Starting Date an annuity for the life of a Participant and a 50% survivor annuity for the life of his Spouse which, together, equal the Actuarial Equivalent of the Participant’s Normal Retirement Pension, Early Retirement Pension, Late Retirement Pension, Disability Retirement Pension or Deferred Vested Retirement Pension, whichever is applicable. If a Participant does not have a Spouse on his Annuity Starting Date, he shall receive the normal form of Pension computed and payable as provided under this Article V unless he has duly elected an optional Pension, as provided in paragraph (b) below. For the purposes of this Section 5.6, the identity of a Participant’s Spouse shall be determined on the Participant’s Annuity Starting Date.

The Participant may request information regarding the Automatic Option within nine (9) months prior to the date when he would first become eligible to commence receiving a Pension hereunder. A written reply will be made within thirty (30) days of his request. During an election period beginning no less than 30 and no more than 180 days prior to the commencement of benefits and ending on the date on which the benefits commence, the Participant may elect in writing to the Committee not to receive payment of his vested Pension in the Automatic Option, in which case the normal form of payment described in this Article V shall be applicable unless an optional form becomes operative under paragraph (b) below. During the election period the Participant may revoke and choose elections in writing to the Committee. A married Participant who elects not to receive the Automatic Option must obtain the consent of his Spouse for an optional pension other than as described in Section 5.6(b)(ii), which shall not be effective unless: (a) the Participant’s Spouse consents in writing to the election; (b) the election designates a specific alternate beneficiary (including any class of beneficiaries or any contingent beneficiaries) which may not be changed without any further spousal consent, except as hereinafter provided; (c) the Spouse’s consent acknowledges the effect of the election; and (d) the Spouse’s consent is witnessed by a Plan representative or notary public. If it is established to the satisfaction of a Plan representative that such written consent may not be obtained because there is no Spouse or the Spouse cannot be located, a waiver will be deemed a qualified election. Any consent by a Spouse under this Section (or establishment that the consent of the Spouse cannot be obtained) shall be effective only with respect to such Spouse. A consent that permits designations by the Participant without any requirement of further consent by the Spouse must acknowledge that the Spouse has the right to limit consent to a specific beneficiary, and a specific form of benefit where applicable, and that the Spouse voluntarily elects to relinquish either or both of such rights. The written explanation shall also include the terms and conditions of the optional Pension forms of benefits under this Section and their relative values and the eligibility conditions required for them. A revocation of a prior waiver may be made by a Participant without the consent of the Spouse at any time prior to the commencement of benefits. The number of revocations shall not be limited. For purposes of this Section, the Spouse or surviving Spouse of the Participant shall be deemed the recipient under the Automatic Option, provided that a former Spouse will be treated as the Spouse or surviving Spouse to the extent provided under a qualified domestic relations order as described in Section 414(p) of the Code.

(b) Optional Pension :

(i) Optional Pensions Under this Plan : Any Participant who is entitled to receive a Pension under this Article V may elect, in lieu of his normal form of Pension or the Automatic Option, any one of the following optional forms of Pension (the value of the expected aggregate payments under any of which shall be the Actuarial Equivalent of his normal form of Pension):

(A) Life and Period Certain. A pension payable for the Participant’s life and, if one hundred twenty (120) or sixty (60) (as designated by the Participant) monthly installments have not been paid prior to the Participant’s death, payment of such pension will be continued in the same amount to the beneficiary or beneficiaries designated by the Participant for the balance of the period selected by the Participant.

(B) Joint and Survivor. A joint and survivor Pension for the Participant and his Spouse under which the member shall receive a Pension payable for his life, and payments in the amount equal to 75% or 100% (as elected by the Participant) of such Pension shall after the Participant’s death, be continued to his surviving Spouse during such surviving Spouse’s lifetime.

(1) A Participant who terminates Service on or after October 1, 2004 and on or before December 31, 2009 with entitlement to a vested accrued Pension having a single sum present value that does not exceed $50,000 as of the date of such termination of Service may, within 60 days after such termination, may elect to receive his Pension in the form of an immediate lump-sum distribution in complete satisfaction of the Plan’s obligations under this Article V.

(2) A Participant who terminates Service after December 31, 2009 may elect to receive his vested accrued Pension in the form of an immediate lump-sum distribution in complete satisfaction of the Plan’s obligations under this Article V; provided, however, that such election shall be submitted to the Committee in writing on or before the 60th day following the date on which the Committee provides notice of such election right to the Participant and shall comply with any additional procedures established by the Committee, in its sole discretion.

(ii) Optional Pensions Under the Cabot Corporation Cash Balance Plan : In addition, a Participant who has a benefit as detailed in Exhibit I, a copy of which is attached hereto and is hereby incorporated into this Plan, due to participation under the Cabot Corporation Cash Balance Plan may elect to have such benefit paid in a lump sum payment or in any optional form of payment described below; provided, however, that if the Participant has a Spouse on his Annuity Starting Date the Actuarial Equivalent of such benefit shall be paid in the form of a joint and 50% survivor annuity unless he elects to receive the benefit in a lump sum or an optional form described below in accordance with the election provisions in Section 5.6(a). A Participant who has an additional benefit as detailed in Exhibit IV, a copy of which is attached hereto and is hereby incorporated into this Plan, due to the grandfather provisions under the Cabot Corporation Cash Balance Plan shall have such additional amount added to the benefit as detailed in Exhibit I in a manner as described below.

(A) Lump Sum Option : The lump sum payment is determined as the sum of (1) and (2), subject to a minimum of (3) below:

(1) The product of the accrued benefit detailed in Exhibit I and the applicable annuity value based on the Participant’s age as of his benefit commencement date, the Applicable Interest Rate, and the Applicable Mortality Table.

(2) The product of the additional benefit detailed in Exhibit IV, reduced by one quarter of one percent (0.25%) per month for each month by which the Participant’s age as of his benefit commencement date precedes the Participant’s attainment of age sixty-two (62) and the annuity value based on the Participant’s age as of his benefit commencement date. For purposes of this subsection (2), the annuity value shall be determined using the Applicable Interest Rate and the Applicable Mortality Table.

(3) The sum of the December 31, 1990 Cash Balance Plan Balance detailed in Exhibit I and the December 31, 1990 Grandfather Balance detailed in Exhibit IV, increased with interest at 5% per annum from December 31, 1990 to the date of benefit commencement.

(iii) Single Life Annuity Option : A benefit which is a level monthly annuity for the lifetime of the Participant (with no survivor benefits) equal to the sum of (A) and (B), subject to (C) below:

(A) the Actuarial Equivalent of the accrued benefit detailed in Exhibit I. For purposes of this subsection (A), the Actuarial Equivalent shall be determined using the Applicable Interest Rate and the Applicable Mortality Table.

(B) the additional benefit detailed in Exhibit IV, reduced by one quarter of one percent (0.25%) per month for each month by which the Participant’s age as of his benefit commencement date precedes the Participant’s attainment of age sixty-two (62).

(C) In the event that the minimum lump sum provisions of subparagraph (iii)(C) of this Section apply, the level monthly annuity amount shall be equal to the result of the minimum lump sum value determined in subparagraph (iii)(C) of this Section divided by the applicable annuity value based on the Participant’s age as of his benefit commencement date, the Applicable Interest Rate, and the Applicable Mortality Table.

The “applicable interest rate” is the interest rate which would be used as of the first day of the calendar year containing the distribution by the Pension Benefit Guaranty Corporation for determining the present value of a lump sum distribution on Plan termination.

(D) Single Life Increasing Annuity Option : an increasing monthly annuity for the lifetime of the Participant equal to the lump sum amount, determined as in (i) above divided by the factor from the table of factors (Table A, a copy of which is attached hereto and is hereby incorporated into this Plan) that corresponds to the Participant’s attained age as of the first of the month coinciding with or immediately following the determination date.

Increases in the monthly annuity amount shall be effective each January 1 occurring after the determination date and shall be equal to:

(1) For the first such January 1, 1/12th of the percentage change in the Consumer Price Index for the Urban Wage Earners - All City Average for the 12-month period ending with September 30 of the calendar year preceding the calendar year containing such determination date, multiplied by the number of monthly payments made in the calendar year of the determination date.

(2) For each succeeding January 1, the percentage change in the Consumer Price Index for Urban Wage Earners - All City Average for the 12-month period ending with September 30 of the preceding calendar year.

(iv) Joint and Survivor Annuity Option : A reduced monthly benefit that is a joint and 50 percent, or joint and 75 percent, or joint and 100 percent (as determined by the Participant) survivor level annuity that is the Actuarial Equivalent of the Participant’s single life annuity amount. Such joint and survivor level annuity is a level monthly annuity under which (i) the Participant will receive a monthly annuity for life and (ii) following the Participant’s death, and Participant’s Beneficiary (if surviving the Participant) will receive a monthly annuity for life with the monthly annuity payment equal to either 50 percent, 75 percent, or 100 percent of the monthly annuity which would have been payable to the Participant had he lived. If the Participant’s Beneficiary dies after the Participant has commenced receiving benefits (but before the Participant’s death), the Participant shall continue to receive the amount payable to such Participant under the joint and survivor level annuity form for the remainder of the Participant’s lifetime, with the last payment to be made for the month in which his death occurs. Thereafter no further benefits shall be payable under the Plan in respect of the Participant.

For purposes of this paragraph, the Actuarial Equivalent benefit shall be determined by multiplying the single life annuity amount determined in (ii) above, by the following factor, depending upon which percentage is selected to be continued to the beneficiary:


Percentage Selected		Factor
50 percent		0.88
75 percent		0.83
100 percent		0.79

If the Beneficiary is other than the Participant’s Spouse and if, as of the Participant’s Benefit Commencement Date, the Beneficiary’s age on his or her last birthday is more than five years less than the Participant’s age on his or her last birthday, the amounts of the monthly annuity payable to the Participant and Beneficiary shall be computed based on the above factors and then reduced by 1 percent of the percentage selected for each year by which difference in ages exceeds five years. The individual who is the Participant’s Spouse on the date the Participant has commenced receiving benefits shall be treated as his spouse for purposes of this option so long as such Spouse shall live, whether or not the Spouse is subsequently divorced from the Participant or the marriage otherwise terminated thereafter, except as a qualified domestic relations order described in Section 414(p) of the Code shall otherwise provide.

(v) Fifteen Years Certain and Continuous Option : A reduced benefit which is a level monthly annuity for the life of the Participant and, in the event of his death before 180 monthly payments have been made to him (if the person designated in his option election form as his Beneficiary for purposes of this option is then living), with the remainder of said 180 monthly payments paid to his Beneficiary. In the event the Participant’s Beneficiary dies before a total of 180 payments have been made, any payments remaining shall be paid in a lump sum to a succeeding beneficiary, if living, or if also deceased, to the estate of the last of the retiree and beneficiaries to die. Such benefit shall be equal to the single life annuity amount, determined in (ii) above, multiplied by 0.83.

(vi) Single Life/Cash Refund Annuity Option : A benefit which is a reduced and level monthly annuity for the lifetime of the Participant, with the guarantee that an amount will be payable to the Participant’s Beneficiary in the form of a lump sum payment if the total of all payments made to the Participant by the time of his death does not equal or exceed the lump sum value as determined under (i) above. The monthly benefit under this option shall be the Participant’s single life annuity amount determined in (ii) above, multiplied by 0.90.

(vii) Joint and 50 Percent Survivor Increasing Annuity Option : An increasing monthly annuity under which (a) the Participant will receive a reduced monthly annuity which will increase as for the Single Life Increasing Annuity in (iii) above and (b) following the Participant’s death the Participant’s Spouse (if surviving the Participant) will receive a monthly annuity for life equal to 50% of the monthly annuity which would have been payable to the Participant had he lived.

The reduced monthly annuity payable to the Participant under this option shall be equal to the amount determined under (iii) above multiplied by a factor based on the Participant’s age as of his or her nearest birthday as of his Benefit Commencement Date as follows:


Participant’s Age as of Benefit Commencement Date		Factor
Younger than 45		0.96
Between 45 and 55		0.92
55 and older		0.88

(viii) Optional Pensions Under the Cabot Corporation Retirement Income Plan : In addition, a Participant who has a monthly annuity guaranteed by the Prudential Insurance Company (as detailed in Exhibit II) due to participation under the Cabot Corporation Retirement Income Plan may elect to have such monthly annuity paid in any optional form of payment described below.

(A) Single Life Annuity Option : A benefit which is a level monthly annuity for the lifetime of the Participant (with no survivor benefits). For a Participant who retires after meeting the requirements for Early Retirement set forth in Section 4.3, the monthly benefit amount shall be equal to the Participant’s accrued benefit detailed in Exhibit II, reduced by one quarter of one percent (0.25%) per month for each month by which the Participant’s age as of his benefit commencement date precedes the Participant’s attainment of age sixty-two (62).

For a Participant who terminates Service prior to meeting the requirements for Early Retirement set forth in Section 4.3, the monthly benefit amount shall be equal to the Participant’s accrued benefit detailed in Exhibit II, reduced by one-half of one percent (0.50%) per month for each month by which the Participant’s age as of his benefit commencement date precedes the Participant’s attainment of age sixty-five (65).

(B) Joint and Survivor Annuity Option : A reduced monthly benefit that is a joint and 50%, or joint and 75%, or joint and 100% (as determined by the Participant) survivor level annuity that is the Actuarial Equivalent of the Participant’s accrued benefit detailed in Exhibit II. Such joint and survivor level annuity is a level monthly annuity under which (i) the Participant will receive a monthly annuity for life and (ii) following the Participant’s death the Participant’s Beneficiary (if surviving the Participant) will receive a monthly for life with the monthly annuity payment equal to either 50%, 75% or 100% of the monthly annuity which would have been payable to the Participant had he lived. If the Participant’s Beneficiary dies after the Participant has commenced receiving benefit (but before the Participant), the Participant shall continue to receive the amount payable to such Participant under the joint and survivor level annuity form for the remainder of the Participant’s lifetime, with the last payment to be made for the month in which his death occurs. Thereafter no further benefits shall be payable under the Plan in respect of the Participant. The individual who is the Participant’s Spouse on the date the Participant has commenced receiving benefits shall be treated as his spouse for purposes of this option so long as such Spouse shall live, whether or not the Spouse is subsequently divorced from the Participant or the marriage otherwise terminated thereafter, except as a qualified domestic relations order described in Section 414(p) of the Code shall otherwise provide.

For purposes of this paragraph, the Actuarial Equivalent benefit shall be determined by multiplying the single life annuity amount, determined under (i) above, by the following factor, depending upon which percentage is selected to be continued to the Beneficiary, and whether the Beneficiary is the Participant’s Spouse:

Factor


Percentage Selected	Beneficiary is Participant’s Spouse	Beneficiary is other than Participant’s Spouse
50%	1.00	0.88
75%	0.94	0.83
100%	0.89	0.79

(C) Fifteen Years Certain and Continuous Option : A reduced benefit which is a level monthly annuity for the life of the Participant, and, in the event of his death before 180 monthly payments have been made to him (if the person designated in his option election form as his Beneficiary for purposes of this option is then living) the remainder of said 180 monthly payments paid to his Beneficiary. In the event the Participant’s Beneficiary dies before a total of 180 payments have been made, any payments remaining shall be paid in a lump sum to a succeeding Beneficiary, if living, or if also deceased, to the estate of the last Beneficiary to die. Such benefit shall be equal to the single life annuity amount determined in (i) above, multiplied by 0.98.

(D) Lump Sum Option : A Participant who is entitled to cash settlement credits as detailed in Exhibit III, a copy of which is attached hereto and is hereby incorporated into this Plan, may elect to have such amount paid as a lump sum, provided that the lump sum value of his benefit as detailed in Exhibit II shall be reduced by the amount of such cash settlement credits.

(ix) Election of Optional Pension : The election of an optional pension shall be governed by the following provisions:

(A) Election of Option : Application for an optional form of Pension must be made on the prescribed form on or before his termination of Service.

(B) Cancellation or Change of Option : By making application to the Committee on the prescribed form, a Participant who has not terminated Service may cancel or change his election of an optional form of Pension at any time before commencement of benefits. An option may not be cancelled or changed after payments commence thereunder.

(C) Beneficiary Designation : Each Participant who has elected the life and period certain optional form shall have the right at any time to designate and to rescind or change any designation of a primary and contingent beneficiary or beneficiaries to receive the remaining installments of pension payments in the event of his death prior to the expiration of the 60- or 120- month period (as applicable). Any such designation, change or rescission of designation, shall be made in writing by filling out and furnishing to the Committee the appropriate form prescribed by the Committee. The contingent beneficiary or beneficiaries shall be entitled to receive any unpaid death benefit only if no primary beneficiary is alive or legally entitled to receive such benefit on the date of payment of the benefit or any installment thereof. The estate, assignee or appointee of either a primary or contingent beneficiary shall have no interest in or right to receive any death benefit payment not actually made before such beneficiary’s death. The last such designation received by the Committee shall be controlling over any testamentary or other disposition; provided, however, that no designation, rescission or change under this Plan shall be effective unless received by the Committee prior to the Participant’s death, and in no event shall it be effective as of a date prior to such receipt. If there is no designated beneficiary alive at the time of any payment of a death benefit, then the Actuarial Equivalent of the death benefit, or balance thereof, shall be paid to the estate of the deceased Participant. An Employer shall not be named as a beneficiary. If the Committee shall be in doubt as to the right of any beneficiary designated by a deceased Participant to receive any unpaid death benefit, the Committee may direct the Trustee to pay the amount in question to the estate of such Participant, in which event the Trustee, the Employer, the Committee and any other person in any manner connected with the Plan shall have no further liability with respect to the amount so paid.

(D) Special Limitation : Notwithstanding any provisions of this Section 5.6(b)(ix) to the contrary, the amount to be distributed each year to a Participant under an optional form of benefit described in this Section must be at least an amount equal to the quotient obtained by dividing the Participant’s entire interest by the life expectancy of the Participant or joint and last survivor expectancy of the Participant and designated beneficiary. Life expectancy and joint and life survivor expectancy shall be computed by the use of the return multiples contained in Treasury Regulation § 1.72-9. For purposes of this computation, a Participant’s life expectancy may be recalculated no more frequently than annually, however, the life expectancy of a non Spouse beneficiary may not be recalculated. If the Participant’s Spouse is not the designated beneficiary, the method of distribution selected must assure that greater than fifty percent (50%) of the present value of the amount available for distribution is paid within the life expectancy of the Participant.

(E) Proof of Age : Proof of age and such other information as may be required in determining the amount of an optional form of Pension must be furnished to the Committee upon its request.

(F) Election of Certain Optional Forms of Benefit Under the Cabot Corporation Cash Balance Plan and Cabot Corporation Retirement Income Plan . An election of the Automatic Option or one of the respective optional forms of benefit described in Paragraph (b), above, shall require the Participant to select from among the following optional forms of benefit with respect to the benefits detailed under Exhibits I and II due to participation under the Cabot Corporation Cash Balance Plan and the Cabot Corporation Retirement Income Plan, respectively:


COGC Plan Form	Cash Balance Form	Retirement Income Plan Form
(1) Life Annuity	(1) Life Annuity, Increasing Single Life Annuity, Single Life/Cash Refund Annuity or Lump Sum	(1) Life Annuity
(2) 50% Joint and Survivor Annuity	(2) Joint and 50% Survivor Increasing Annuity, 50% Joint and Survivor Annuity, or Lump Sum	(2) 50% Joint and Survivor Annuity
(3) 75% or 100% Joint and Survivor Annuity	(3) Corresponding Percentage Joint and Survivor Annuity, or Lump Sum	(3) Corresponding Percentage Joint and Survivor Annuity
(4) Life and Period Certain Annuity	(4) 15-year Certain and Continuous Annuity, or Lump Sum	(4) 15-year Certain Annuity
(5) Lump Sum, if eligible

An election of one form of payment in a particular plan form listed above shall not restrict a Participant’s election of a different form of payment for another plan form, if the Participant is so eligible to elect.

All optional forms of benefits which are “Section 411(d)(6) protected benefits,” as described in Treasury Regulation § 1.411(d)-4, shall continue to be optional forms of benefits for Participants to whom the optional forms apply notwithstanding any subsequent amendment of the Plan purporting to revise or delete such optional form of benefit and notwithstanding any contrary provision of paragraph (b) of this Section 5.6.

(c) At any time the Committee may cause the Plan to purchase and distribute to a Participant a commercial annuity that will thereafter provide the Participant’s Pension otherwise payable from the Plan.

5.7 Duration of Pensions : Except for the Spouse’s Pension set forth in Section 6.1 and except as may be provided under the Automatic Option or under the optional forms of Pension both as described in Section 5.6, all Pensions payable under Article V shall be paid monthly commencing on the applicable of (i) the Participant’s Normal Retirement Date, (ii) the commencement date of his Early, Deferred Vested or Disability Retirement benefits or (iii) his Late Retirement Date, and shall be payable for the life of the retired Participant. The Automatic Option shall be paid monthly and shall be payable for the joint lives of the Participant and his Spouse. The Spouse’s Pension shall be paid monthly and shall be payable for the life of the Spouse. Any other optional Pension shall continue for the period specified under the option elected.

5.8 Payment of Small Benefits : The payment of a benefit under the Plan whose present value does not exceed $1,000 shall be made in a lump sum cash payment, unless the Participant elects to have such amount paid directly to an eligible retirement plan in the form of a direct rollover. The amount thereof shall be the Actuarial Equivalent of the Accrued Pension otherwise payable. No distribution shall be made under this Section 5.8 without the Participant’s (and the Participant’s Spouse, if any) consent if the value thereof is greater than $5,000. No distribution may be made after the Annuity Starting Date unless the Participant and the Participant’s Spouse (or, where the Participant has died, the surviving Spouse) consent in writing to such distribution. Notwithstanding the above, in the event of a distribution referenced above which is greater than $1,000 but less than $5,000, if the Participant does not elect to have such distribution paid directly to an eligible retirement plan specified by the Participant in a direct rollover, or to receive the distribution directly in a lump-sum cash payment in accordance with the provisions stated elsewhere herein, then the Committee will pay the distribution in a direct rollover to an individual retirement plan or account designated by the Committee in its sole discretion.

5.9 Waiver of Waiting Period : Notwithstanding anything in the foregoing to the contrary, if a distribution is one to which Sections 401(a)(11) and 417 of the Code do not apply, such distribution may commence less than 30 days after the notice required under Section 1.411(a)-11(c) of the Income Tax Regulations is given, provided that (a) the Committee clearly informs the Participant that the Participant has a right to a period of at least 30 days after receiving the notice to consider the decision of whether or not to elect a distribution (and, if applicable, a particular distribution option), and (b) the Participant, after receiving the notice, affirmatively elects a distribution. If a distribution is one to which Sections 401(a)(11) and 417 of the Code does apply, the Participant may elect (with any applicable spousal consent) to waive any requirement that the written explanation required under Code Section 417 be provided at least 30 days before the annuity starting date (or to waive the 30 day requirement with respect to an explanation provided after the annuity starting date) if the distribution commences more than 7 days after such explanation is provided.

5.10 Benefits after Reemployment : If a Participant terminates his Service on or after the Effective Date and is subsequently reemployed by an Employer or an Affiliate, his Benefit payments, if any, shall immediately cease, and upon his subsequent termination of Service he shall receive a Benefit determined under Section 5.1, 5.2, 5.3, 5.4 or 5.5, but reduced by the Actuarial Equivalent of the Benefit payments, if any, which he received prior to his reemployment.

5.11 Minimum Date for Commencement of Benefits : Except as provided below, if a Participant is employed by the Company on the April 1 following the calendar year in which the Participant attains age 70 ¹ / 2 , such Participant may choose to commence distribution of the Participant’s benefit either on the April 1 of the calendar year following the calendar year in which (i) the Participant attains age 70 ¹ / 2 or (ii) the Participant retires from the Company. Notwithstanding any provision of the Plan to the contrary, any benefits to which a Participant who is a “5% owner” (as described in Section 416(i)(1) of the Code determined with respect to the Plan Year ending in the calendar year in which such individual attains age 70 ¹ / 2 ) of the Company is entitled shall commence not later than April 1 of the calendar year following the calendar year in which the Participant attains age 70 ¹ / 2 , whether or not the Participant’s employment has terminated in such year. If a Participant commences distribution of his benefit later than the April 1 following the end of the calendar year such Participant attains age 70 ¹ / 2 , then such Participant’s benefit shall be actuarially increased to take into account the period after age 70 ¹ / 2 in which he is not receiving benefits, in accordance with Code Section 401(a)(9)(C)(iii) and applicable Internal Revenue Service guidance addressing the same. Such actuarial increase is generally the same as, and not in addition to, the actuarial increase required for same period under Code Section 411 to reflect the delay in payments after Normal Retirement Age; provided, however, that the actuarial increase shall be provided during such period even if the Participant is otherwise subject to a suspension of his benefit under Section 5.10.

5.12 Required Minimum Distributions :

(a) General Provisions : All distributions shall be determined and made in accordance with Section 401(a)(9) of the Code and the Treasury regulations promulgated thereunder.

(b) Lost Participants : A Participant who is a Lost Participant (as defined below) shall receive his pension determined as of his Required Beginning Date (as defined below) and commencing on a date after his Required Beginning Date (the “Distribution Date”), in accordance with, and subject to, the requirements of this Section 5.12(b). This Section 5.12(b) shall not be available or applicable for a Participant who is not a Lost Participant.

The Administrator shall furnish a written explanation of the terms and conditions of the automatic form and the effect of refusing it to a Lost Participant no less than 30 days and no more than 180 days prior to the Distribution Date of his pension. The Lost Participant may request additional information regarding the automatic form within 60 days of the furnishing of such explanation to him. A written reply will be made within 30 days of his request. During such election period, the Lost Participant may, with the written consent of his Lost Spouse (as defined below) in accordance with Section 5.6 herein, elect in writing to the Administrator not to receive the automatic form, in which case the Lost Participant may elect payment in one of the optional forms permitted hereunder. Throughout the election period, the Lost Participant may file written revocations or written elections with the Administrator as provided in Section 5.6. The foregoing notwithstanding, the Lost Participant may elect (with written consent of his Lost Spouse) to waive the requirement that the written explanation of the automatic form described herein be provided at least 30 days prior to his Distribution Date, provided that the distribution commences more than 7 days after such explanation is provided to the Lost Participant.

If the Administrator does not receive the Lost Participant’s completed election form by the 60th day after the written explanation of the automatic form was provided, then such Lost Participant’s pension shall be paid in the automatic form as soon as administratively practicable.

Benefits will commence as of his Distribution Date actuarially adjusted to reflect commencement at his Required Beginning Date rather than his Normal Retirement Date or Postponed Retirement Date, as applicable, and notwithstanding any other provision of the Plan to the contrary, the Plan will pay to him an amount equal to missed payments from the Required Beginning Date to the Distribution Date, with interest being paid to the Lost Participant on such amount based on the applicable interest rate for purposes of calculating lump sums outlined elsewhere herein.

For purposes of this Section 5.12(b):

“Lost Participant” means a Participant (i) who does not commence his pension prior to his Required Beginning Date, (ii) whose location is unknown to the Administrator as of his Required Beginning Date, and (iii) who, subsequent to his Required Beginning Date, is either located by the Administrator or notifies the Plan of his location and/or requests information concerning the commencement of his pension.

“Required Beginning Date” means for a Participant who is not a “5% owner” (as defined in Code Section 416), the April 1 following the later of (i) the calendar year in which the Participant attains age 70 ¹ / 2 or (ii) the calendar year in which the Participant’s Active Service terminates. For a Participant who is a 5% owner, “Required Beginning Date” means the April 1 following the calendar year in which the Participant attains age 70 ¹ / 2 .

“Lost Spouse” means the Lost Participant’s Spouse as of the Required Beginning Date. For purposes of this definition, the Lost Spouse or surviving Lost Spouse of the Participant shall be deemed the recipient under the Qualified Joint and Survivor Annuity, provided that a former Spouse will be treated as the Lost Spouse or surviving Lost Spouse to the extent provided under a qualified domestic relations order as described in Section 414(p) of the Code.

5.13 Direct Rollovers : Notwithstanding any provision of the Plan to the contrary that would otherwise limit a Distributee’s election under this Section, a Distributee may elect, at the time and in the manner prescribed by the Committee, to have any portion of an “Eligible Rollover Distribution” paid directly to an “Eligible Retirement Plan” specified by the Distributee in a Direct Rollover. For the purposes of this Section the following definitions shall apply:

(a) “Eligible Rollover Distribution” shall mean any distribution of all or any portion of the balance to the credit of the Distributee, except that an Eligible Rollover Distribution does not include: any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the Distributee or the joint lives (or joint life expectancies) of the Distributee and the Distributee’s designated beneficiary, or for a specific period of ten years or more; any distribution to the extent such distribution is required under Section 401(a)(9) of the Code; and the portion of any distribution that is not includable in gross income (determined without regard to the exclusion for net unrealized appreciation with respect to employer securities).

(b) “Eligible Retirement Plan” shall mean (i) an individual retirement account described in Section 408(a) of the Code or Section 408A of the Code, (ii) an individual retirement annuity described in Section 408(b) of the Code, (iii) an annuity plan described in section 403(a) of the Code, (iv) an annuity contract described in Section 403(b) of the Code, (v) an eligible plan under Section 457(b) of the Code which is maintained by a state, political subdivision of a state, or any agency or instrumentality of a state or political subdivision of a state and which agrees to separately account for amounts transferred into such plan from this Plan, or (vi) a qualified trust described in Section 401(a) of the Code, that accepts the Distributee’s eligible Rollover Distribution. The definition of Eligible Retirement Plan shall also apply in the case of a distribution to a surviving spouse, or to a spouse or former spouse who is the alternate payee under a qualified domestic relation order, as defined in Section 414(p) of the Code and a non-spouse beneficiary to the extent provided in Section 829 of the Pension Protection Act of 2006 as provided in Section 5.13(e).

(c) “Distributee” shall mean a Participant or former Participant of the Plan. In addition, the Participant’s or former Participant’s surviving spouse and the Participant’s or former Participant’s spouse or former spouse who is the alternate payee under a qualified domestic relations order, as defined in Section 414(p) of the Code, are Distributees with regard to the interest of the spouse or former spouse.

(d) “Direct Rollover” shall mean a payment by the Plan to the Eligible Retirement Plan specified by the Distributee.

(e) “Non-Spouse beneficiary Rollovers” Notwithstanding any provision of the Plan to the contrary, to the extent provided in Section 829 of the Pension Protection Act of 2006, in the case of a designated beneficiary (within the meaning of Section 401(a)(9) of the Code) who is a person or trust other than the Participant’s Spouse, the beneficiary may elect to have all or part of the Participant’s Eligible Rollover Distribution distributed in a direct trustee-to-trustee transfer to an inherited individual retirement account described in Section 408(a) or (b) or Section 408A of the Code (an “Inherited IRA”) if the following requirements are satisfied:

(i) The Committee (or its delegate) is provided a timely request to make the direct trustee-to-trustee transfer to the Inherited IRA by the beneficiary, in the form and manner prescribed by the Committee, prior to the date the Participant’s accrued benefit is distributed pursuant to Article V.

(ii) The beneficiary represents to the Committee in writing that an Inherited IRA has been established for the purpose of receiving the distribution on behalf of such designated beneficiary in a manner that identifies the IRA as an IRA with respect to the deceased Participant and also identifies the designated beneficiary.

(iii) The amount distributed in a trustee-to-trustee transfer to an IRA satisfies the requirements for an Eligible Rollover Distribution as set forth above in this Section 5.13 other than the requirement that the designated beneficiary satisfies the definition of “Distributee” in Section 5.13(c)).

(iv) The transfer otherwise meets all other requirements of Code Section 402(c)(11) and any regulations and guidance issued thereunder.

5.14 Limitations on Benefit Accruals : Notwithstanding any provision of the Plan to the contrary, except as otherwise provided by Treasury Regulations, effective as of October 1, 2008, in the event that the Plan’s adjusted funding target attainment percentage (as such term is defined in Code Section 436(j)(2)) is certified by the Plan’s actuary (or deemed under the Treasury Regulations) to be less than 60%, all future benefit accruals under the Plan shall cease as of such certification (or deemed) date. The limitation provided in this Section 5.14 shall cease to apply as of the date the actuary certifies that the Plan’s adjusted funding target attainment percentage is equal to or greater than 60%. For the 2009 Plan Year, the Plan’s adjusted funding target attainment percentage shall be the greater of the adjusted funding target attainment percentage for the 2008 Plan Year or the 2009 Plan Year for purposes of this Section 5.14.

5.15 Limitations on Accelerated Benefit Distributions : Notwithstanding any provision of the Plan to the contrary, effective as of October 1, 2008, payments shall be made in accordance with the provisions of this Section 5.15 and Section 436 of the Code and accompanying Treasury regulations in the event that such provisions become applicable. Accordingly, the Plan shall not make any prohibited payment (as such term is defined below) in the event that the Plan’s adjusted funding target attainment percentage (as such term is defined in Section 436(j)(2) of the Code) is certified by the Plan’s enrolled actuary (or deemed under the Treasury regulations) to be less than 60%, or less than 100% in the event the Company is in bankruptcy proceedings. Except as otherwise provided by Section 436 of the Code or applicable Treasury regulations, the limitation provided in this Section 5.15 shall cease to apply as of the date the Plan’s enrolled actuary certifies that the Plan’s adjusted funding target attainment percentage is equal to or greater than 60%, or equal to or greater than one hundred percent (100%) in the event the Company is in bankruptcy proceedings.

In the event that the Plan’s adjusted funding target attainment percentage is certified by the Plan’s enrolled actuary (or deemed under the Treasury regulations) to be 60% or greater, but less than 80%, the Plan may not pay any prohibited payment exceeding the lesser of: (i) 50% of the amount otherwise payable under the Plan, and (ii) the present value of the maximum Pension Benefit Guaranty Corporation guarantee with respect to the Participant (determined under guidance prescribed by the Pension Benefit Guaranty Corporation, using the interest rates and mortality table specified in Section 417(e)(3) of the Code); provided, however, that only one payment under the exception set forth in this paragraph may be made with respect to any Participant during any period of consecutive Plan Years to which the limitation applies. For purposes of this paragraph, a Participant and any beneficiary and/or alternate payee of such Participant shall be treated as one Participant. In the event that the Participant’s accrued benefit is allocated to an alternate payee and one or more other persons, the amount that may be distributed is allocated in the same manner unless the applicable qualified domestic relations order, as defined in Section 414(p) of the Code, provides otherwise.

For purposes of this Section 5.15, “prohibited payment” means (i) any payment in excess of the monthly amount paid under a retirement annuity (plus any social security supplement described in the last sentence of Section 411(a)(9) of the Code, if applicable) to a Participant or beneficiary whose commencement of benefits occurs during any period a limitation under Section 5.15 is in effect, (ii) any payment for the purchase of an irrevocable commitment from an insurer to pay benefits, or (iii) any other payment specified in Treasury regulations; provided, however, that such term shall not include the payment of a benefit under Section 5.8.

ARTICLE VI

DEATH BENEFIT

6.1 Death While in Service but Prior to Commencement of Pension : In the event of the death of a Participant who is survived by a Spouse and who dies (1) while in the active employment of an Employer or Affiliate or (2) while on an Authorized Absence pursuant to Section 2.2(a) or 2.2(c) and after completion of the Vesting Service requirements for a Deferred Vested Retirement Pension on the date of his death, such Spouse shall be entitled to receive a Spouse’s Pension commencing as of the first day of the calendar month next following the Participant’s date of death or the date he would have attained age fifty-five (55), whichever is later, and payable through the first day of the month during which the Spouse’s death occurs. The monthly amount of the Spouse’s Pension provided in this Section shall be an amount equal to the Pension payments which would have been made to the Spouse under the Automatic Option provided for in Section 5.6(a) if the Participant had elected such Automatic Option commencing on the date of his Retirement immediately prior to his Retirement and if his Retirement had occurred on the day before the date of his death.

6.2 Death After Retirement but Prior to Commencement of Pension : In the event of the death of a Participant after Normal, Early or Late Retirement (but not after Deferred Vested Retirement) but prior to the commencement of his Pension, the normal form, Automatic Option or other Optional Pension, whichever is applicable, shall take effect as though the Participant had commenced to receive his Pension on the day of his death. In the event of the death of a Participant after Disability Retirement but prior to the commencement of his Pension, the deceased Participant’s Spouse, if any, shall be entitled to receive the benefit such Spouse would have received under the Automatic Option had such Participant commenced to receive such benefit on the date of his death computed on the basis of his Benefit Service and Vesting Service accrued as of the date of his death.

6.3 Death After Deferred Vested Retirement but Prior to Commencement of Pension : In the event of the death of a Participant after he terminates employment with entitlement to a Deferred Vested Pension under the Plan but prior to the commencement of Pension payments, the Participant’s Spouse, if any, shall be entitled to receive a survivor’s annuity commencing as of the first day of the calendar month next following the Participant’s date of death or the date on which such Participant would have attained age fifty-five (55), whichever is later, and payable through the first day of the month during which the Spouse’s death occurs. The monthly amount of the survivor annuity provided in this Section shall be an amount equal to the benefit payments such Spouse would have received under the Automatic Option had such Participant elected to receive such option commencing on the first day of the calendar month next following the later of the Participant’s date of death or the date the Participant would have attained age fifty-five (55).

6.4 Definition of Spouse : For the purposes of this Article VI, the definition of Spouse includes only such person to whom the Participant has been legally married for a period of at least one year at the time of his death, and who is of the opposite sex of the Participant.

6.5 Death Benefits Payable Under the Cabot Corporation Cash Balance Plan and Retirement Income Plan :

(a) Death Benefits Payable under Cabot Corporation Cash Balance Plan . In the event of the death of a Participant who has a benefit as detailed in Exhibit I due to participation in the Cabot Corporation Cash Balance Plan and whose death occurs prior to the commencement of his Pension, his Beneficiary shall be entitled to receive a benefit in the form of a single lump sum benefit calculated as in Section 5.6(b)(ii).

If the Beneficiary is the Participant’s Spouse, the Beneficiary may elect to receive, in lieu of such single sum payment, a benefit in the form of an increasing monthly annuity for life (with no survivor benefits). Such benefit shall be calculated as in Section 5.6(b)(2)(iii), based on the Beneficiary’s attained age as of the first of the month coinciding with or immediately following the determination date.

(b) Death Benefits Payable under Cabot Corporation Retirement Income Plan . In the event of the death of a Participant who is entitled to a benefit under the Cabot Corporation Retirement Income Plan as set forth in Exhibit II, the following provisions shall apply: (i) if the Participant is married at the time of his death and his death occurs while he is in active service with the Company or one of its Affiliates, his Spouse shall receive a monthly pre-retirement annuity in the amount set out under the heading “Monthly Amount of Pre Ret. Annuity” on Exhibit II, in accordance with the terms of the annuity contract purchased in connection with the termination of the Cabot Corporation Retirement Income Plan; (ii) if the Participant is married at the time of his death and his death occurs after his termination from Service with the Company and/or its Affiliates, his Spouse shall receive a monthly benefit in an amount equal to 50 percent (50 %) of the monthly benefit that would otherwise have been payable to the Participant as of his Normal Retirement Date, as set forth under the heading “Monthly Amount of RIP Annuity” on Exhibit II, in accordance with the terms of the annuity contract purchased in connection with the termination of the Cabot Corporation Retirement Income Plan; and (iii) if the Participant is not married at the time of his death, his Beneficiary shall not be entitled to receive any death benefit attributable to the Participant’s participation in the Cabot Corporation Retirement Income Plan.

6.6 Alternate Form of Pension Payment for Spouse : Notwithstanding any other provision of this Plan to the contrary, any Spouse who is or becomes entitled to receive a Pension under the Plan as determined under Section 5.1, which has a single sum present value that does not exceed $50,000 on the date of the Participant’s death, shall be eligible to elect an optional form of Pension payment in accordance with Section 5.6(b)(i) in lieu of the form of Pension payment such Spouse is otherwise entitled.

ARTICLE VII

CLAIM PROCEDURES

7.1 Presenting Claims for Benefits : A “Claims Administrator” shall be appointed by the Committee or, absent such appointment, shall be the Company’s director of benefits, with such Claims Administrator authorized by the Committee to conduct the initial review and render a decision as provided in this Section for all claims for benefits under the Plan. The Committee shall establish administrative processes and safeguards to ensure that benefit determinations made pursuant to this Section 7.1 are made in accordance with the Plan and have been made and applied consistently to similarly situated claimants. Any Participant, Beneficiary of any deceased Participant, or the authorized representative of such claimant (collectively, the “Applicant”) may submit written application to the Claim Administrator for the payment of any benefit asserted to be due him under the Plan. Such application shall set forth the nature of the claim and such other information as the Claim Administrator may reasonably request. Promptly upon the receipt of any application required by this Section, the Claim Administrator shall determine whether or not the Participant or Beneficiary involved is entitled to a benefit hereunder and, if so, the amount thereof and shall notify the Applicant of its findings.

(a) Non-Disability Claims . Except as provided in Section 7.1(b) below, if a claim is wholly or partially denied, the Claim Administrator shall so notify the Applicant within ninety (90) days after receipt of the application by the Claims Administrator, unless special circumstances require an extension of time for processing the application. If such an extension of time for processing is required, written notice of the extension shall be furnished to the Applicant prior to the end of the initial ninety (90) day period. In no event shall such extension exceed a period of ninety (90) days from the end of such initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Claim Administrator expects to render its final decision. Notice of the Claim Administrator’s decision to deny a claim in whole or in part shall be set forth in a manner calculated to be understood by the Applicant and shall contain the following:

(i) the specific reason or reasons for the denial,

(ii) specific reference to the pertinent Plan provisions on which the denial is based,

(iii) a description of any additional material or information necessary for the Applicant to perfect the claim and an explanation of why such material or information is necessary,

(iv) an explanation of the claims review procedure, including applicable time limits, as set forth in Section 7.2 hereof, and

(v) a statement of the claimant’s right to bring a civil suit under Section 502(a) of ERISA following a denial on subsequent review.

(b) Disability Claims . If a claim for benefits based upon a Participant’s disability is wholly or partially denied, the Claim Administrator shall so notify the Applicant within forty-five (45) days after receipt of the application by the Claims Administrator, unless special circumstances require an extension of time for processing the application. If such an extension of time for processing is required, the time for processing may be extended for up to 30 days, if the Claim Administrator determines that the extension is necessary due to matters beyond the control of the Claim Administrator or the Plan and notifies the Applicant, before the expiration of the initial 45 day period, of the circumstances requiring the extension of time and the date by which the claim decision is expected to be made. If, before the end of this 30 day extension period, the Claim Administrator determines that, due to matters beyond the control of the Claim Administrator or the Plan, a decision cannot be rendered within that initial 30 day extension period, an additional 30 day extension may apply if the Applicant is given a notice satisfying the requirements set forth above for the first 30 day extension. Any notice of extension must specifically explain the standards on which entitlement to a benefit is based, the unresolved issues that prevent a decision on the claim, and the additional information needed to resolve those issues. The Applicant will be given at least 45 days in which to provide the specified information. In the event that the extension is a result of an Applicant’s failure to submit information necessary to decide a claim, the period in which the determination must be made will be tolled from the date on which the notification of the extension is sent to the Applicant until the date the Applicant responds to the request for additional information.

Notice of the Claims Administrator’s decision to deny a claim in whole or in part shall be set forth in a manner calculated to be understood by the Applicant and must contain the information described in clauses (i) through (v) of Section 7.1(a). Additionally, the notice of denial must include:

(i) If any internal rule or guideline was relied on in denying the claim, either the specific rule or guideline, or a statement that such a rule or guideline was relied on in denying the claim and that a copy of that rule or guideline will be provided to the Applicant free of charge on request; and

(ii) If the claim denial is based on an exclusion or limit related to medical necessity or experimental treatment, either an explanation of the scientific or clinical judgment for the determination as applied to the involved claimant’s circumstances, or a statement that such an explanation will be provided to the Applicant free of charge upon request.

7.2 Claims Review Procedure : Upon the Claims Administrator’s denial, in whole or in part of a benefit applied for under Section 7.1, an Applicant shall have the right by written to appeal such denial as set forth in this Section 7.2. Benefits under the Plan will only be paid if the Committee decides in its discretion that the claimant involved is entitled to them. The Committee shall establish administrative processes and safeguards to ensure that benefit determinations made pursuant to this Section 7.2 are made in accordance with the Plan and have been made and applied consistently to similarly situated claimants. Except as may be otherwise required by law, the decision of the Committee on review of the claim denial shall be binding on all parties when the Applicant has exhausted the claims procedure under this Section 7.2.

(a) Non-Disability Claims – General Rules . If an application filed by the Applicant under Section 7.1(a) above shall result in a denial by the Claim Administrator of the benefit applied for, either in whole or in part, such Applicant shall have the right, to be exercised by written request filed with the Committee within sixty (60) days after receipt of notice of the denial of the application for a review of the application and of the entitlement to the benefit for which the Applicant applied. Such request for review may contain such additional information and comments as the Applicant may wish to present.

The Committee shall reconsider the application in light of such additional information and comments as the Applicant may have presented, and if the Applicant shall have so requested, shall afford the Applicant or his designated representative a hearing before the Committee. Upon request, the Committee shall provide, free of charge, the Applicant or his designated representative with copies of all “relevant documents” (within the meaning of Department of Labor regulation Section 2560.503-1(m)(8)) (“Relevant Documents”) in its possession, including copies of the Plan document and information provided by the Company relating to the Applicant’s entitlement to such benefit.

The Committee shall render a decision and notify the Applicant of the Committee’s determination on review no later than 60 days after receipt of the Applicant’s request for review, unless the Committee determines that special circumstances (such as the need to hold a hearing) require an extension of time for processing the claim. If the Committee determines an extension of time for processing is required, written notice of the extension shall be furnished to the Applicant prior to the termination of the initial 60 day period. In no event, shall such extension exceed a period of 60 days from the end of the initial period. The extension notice shall indicate the special circumstance requiring an extension of time and the date by which the Committee expects to render the determination on review. In the event that the extension is a result of an Applicant’s failure to submit information necessary to decide a claim, the period in which the determination must be made will be tolled from the date on which the notification of the extension is sent to the Applicant until the date the Applicant responds to the request for additional information.

(i) the specific reason or reasons for the denial; and

(ii) specific reference(s) to the pertinent plan provision(s) on which the denial is based; and

(iii) the Applicant’s right to receive upon request, free of charge, reasonable access to, and copies of, all Relevant Documents, records and other information to his claim; and

(iv) the claimant’s right to bring a civil action under Section 502(a) of ERISA.

(b) Non-Disability Claims – Special Rules . Notwithstanding any other provision of Section 7.2(a), in the event that the Committee holds regularly scheduled meetings at least quarterly, the provisions of this Section 7.2(b) will apply and control, to the extent that this Section 7.2(b) is inconsistent with the provisions of Section 7.2(a). Specifically, in the event that the Committee holds regularly scheduled meetings at least quarterly, the Committee shall render a determination on review of a non-disability claim no later than the date of the Committee meeting next following receipt of the request for review, except that (i) a decision may be rendered no later than the second following Committee meeting if the request is received within 30 days of the first meeting and (ii) under special circumstances which require an extension of time for rendering a decision (including but not limited to the need to hold a hearing), the decision may be rendered not later than the date of the third Committee meeting following the receipt of the request for review. If such an extension of time for review is required because of special circumstances, written notice of the extension shall be furnished to the Applicant prior to the commencement of the extension. In the event that the extension is a result of an Applicant’s failure to submit information necessary to decide a claim, the period in which the determination must be made will be tolled from the date on which the notification of the extension is sent to the Applicant until the date the Applicant responds to the request for additional information.

Additionally, no later than five (5) days after the Committee has reached a final determination on review under this Section 7.2(b), notice of the Committee’s final decision shall be furnished to the Applicant in writing, in the manner descried in Section 7.2(a).

(c) Disability Claims . If an application filed by an Applicant under Section 7.1(b) above shall result in a denial by the Claims Administrator of the disability based benefit applied for, either in whole or in part, such Applicant shall have the right, to be exercised by written request filed with the Committee within one-hundred and eighty (180) days after receipt of notice of the denial of the application, for a review of the application and of the entitlement to the benefit for which the Applicant applied. Such request for review may contain such additional information and comments as the Applicant may wish to present.

The Committee shall reconsider the application in light of such additional information and comments as the Applicant may have presented, and if the Applicant shall have so requested, shall afford the Applicant or his designated representative a hearing before the Committee. Upon request, the Committee shall provide, free of charge, the Applicant or his designated representative with copies of all Relevant Documents in its possession, including copies of the Plan document and information provided by the Company relating to the involved claimant’s entitlement to such benefit. Additionally, the following requirements shall be imposed upon the Committee in reconsidering an Applicant’s request:

(i) The Committee’s review will not give deference to the original claim denial, and the review will not be made by the person who made the original claim denial, or a subordinate of that person;

(ii) In deciding an appeal of any claim denial that is based in any way on a medical judgment, the Committee will consult with a health care professional who has appropriate training and experience in the field of medicine involved in the medical judgment;

(iii) The health care professional consulted by the Committee will not be an individual who was consulted in connection with the original claim denial or a subordinate of any such individual; and

(iv) The Applicant will be provided the identification of medical or vocational experts whose advice was obtained on behalf of the Plan in connection with the claim denial, even if the advice was not relied upon in making the claim denial.

The Committee shall render a decision and notify the Applicant of the Committee’s determination on review within a reasonable period of time, but not later than 45 days after receipt of the Applicant’s request for review, unless the Committee determines that special circumstances (such as the need to hold a hearing) require an extension of time for processing the claim. If the Committee determines an extension of time for processing is required, written notice of the extension shall be furnished to the Applicant prior to the termination of the initial 45 day period. In no event, shall such extension exceed a period of 45 days from the end of the initial period. The extension notice shall indicate the special circumstance requiring an extension of time and the date by which the Committee expects to render the determination on review. In the event that the extension is a result of an Applicant’s failure to submit information necessary to decide a claim, the period in which the determination must be made will be tolled from the date on which the notification of the extension is sent to the Applicant until the date the Applicant responds to the request for additional information.

Notice of the Committee’s final decision shall be furnished to the Applicant in writing, in a manner calculated to be understood by him, and if the Applicant’s claim on review is denied in whole or in part, the notice shall contain the information described in clauses (i) through (iv) of Section 7.2(a). Additionally, the notice of denial shall include:

(i) If any internal rule or guideline was relied on in denying the claim on appeal, either the specific rule or guideline, or a statement that such a rule or guideline was relied on in denying the claim and that a copy of that rule or guideline will be provided to the Applicant free of charge on request; and

(ii) If the claim denial on appeal is based on an exclusion or limit like medical necessity or experimental treatment, either an explanation of the scientific or clinical judgment for the determination as applied to the involved claimant’s circumstances, or a statement that such an explanation will be provided to the Applicant free of charge upon request.

7.3 Disputed Benefits : Benefits under the Plan will be paid only if the Committee decides in its discretion that the applicant is entitled to them. If any dispute shall arise between a Participant or other person claiming under a Participant and the Committee after the review of a claim for benefits, or in the event any dispute shall develop as to the person to whom the payment of any benefit under the Plan shall be made, the Trustee may withhold the payment of all or any part of the benefits payable hereunder to the Participant or other person claiming under the Participant until such dispute has been resolved by a court of competent jurisdiction or settled by the parties involved.

ARTICLE VIII

PLAN ADMINISTRATION

8.1 Allocation of Responsibility Among Fiduciaries for Plan and Trust Administration : Each Employer, the Board of Directors of the Company, the Committee, as designated pursuant to the terms of the Plan, the Trustee and any other person designated as a Fiduciary with respect to the Plan or the Trust Agreement (hereinafter collectively the “Fiduciaries”) shall have only those specific powers, duties, responsibilities and obligations as are specifically given them under this Plan and/or the Trust Agreement. In general, the Employers shall have the sole responsibility for making the contributions provided for under Section 10.2. The Board of Directors shall have the sole authority to appoint and remove the members of the Committee, and to amend or terminate, in whole or in part, this Plan. The Company shall have the sole authority to appoint and remove the Trustee and to amend or terminate, in whole or in part, the Trust Agreement. The Committee shall have the sole responsibility for the administration of the Plan, and to establish and maintain the funding policy and method of the Plan as provided in Section 8.12. The Trustee shall have the sole responsibility for the administration of the Trust Fund and shall have exclusive authority and discretion to manage and control the assets held under the Trust Fund, except to the extent that the authority to manage, acquire and dispose of the assets of the Trust Fund is delegated to an Investment Manager, all as specifically provided in the Trust Agreement. Each Fiduciary warrants that any directions given, information furnished or action taken by it shall be in accordance with the provisions of the Plan or the Trust Agreement, as the case may be, authorizing or providing for such direction, information or action. Furthermore, each Fiduciary may rely upon any such direction, information or action of another Fiduciary as being proper under this Plan or the Trust Agreement, and is not required under this Plan or the Trust Agreement to inquire into the propriety of any such direction, information or action. It is intended under this Plan and the Trust Agreement that each Fiduciary shall be responsible for the proper exercise of its own powers, duties, responsibilities and obligations under this Plan and the Trust Agreement and shall not be responsible for any act or failure to act of another Fiduciary. No Fiduciary guarantees the Trust Fund in any manner against investment loss or depreciation in asset value.

8.2 Appointment of Committee : The Plan shall be administered by an Administrative Committee consisting of at least three (3) persons who shall be appointed by and serve at the pleasure of the Board of Directors. All usual and reasonable expenses of the Committee shall be paid by the Trustee out of the Trust Fund. The members of the Committee shall not receive compensation with respect to their services for the Committee. The Board of Directors shall pay the premiums on any bond secured for the performance of the duties of the Committee members described hereunder and shall be entitled to reimbursement by other Employers for their proportionate shares.

8.3 Records and Reports : The Committee shall exercise such authority and responsibility as it deems appropriate in order to comply with ERISA and any governmental regulations issued thereunder relating to records of Participant’s Service, accrued benefits, the percentage of such benefits which are nonforfeitable under the Plan, and notifications to Participants. The Committee shall file or cause to be filed with the appropriate office of the Internal Revenue Service, the Department of Labor and/or the Pension Benefit Guaranty Corporation all reports, returns, notices and other information required of plan administrators under ERISA, including, but not limited to, the Plan description and summary Plan description, annual reports and amendments thereof to be filed with the Department of Labor, including requests for determination letters, annual reports and registration statements required by Section 6057(a) of the Code, and including reports and notices of reportable events to the Pension Benefit Guaranty Corporation required by Section 4043 of ERISA. The Committee shall make available to Participants and their beneficiaries for examination, during business hours, such records of the Plan as pertain to the examining person and such documents relating to the Plan as are required by ERISA.

8.4 Other Committee Powers and Duties : The Committee shall have such powers as may be necessary to discharge its duties hereunder, including, but not by way of limitation, the following powers and duties:

(a) To decide all questions of eligibility and determine the amount, manner and time of payment of any benefits hereunder;

(b) To prescribe forms or procedures to be followed by Participants or beneficiaries filing applications for benefits, and for other occurrences in the administration of the Plan;

(c) To receive from the Employers and from Participants such information as shall be necessary for the proper administration of the Plan;

(d) To prepare and distribute, in such manner as the Committee determines to be appropriate, information explaining the Plan;

(e) To furnish the Board of Directors, Employers and Participants, upon request, such annual reports with respect to the administration of the Plan as are reasonable and appropriate;

(f) To appoint or employ individuals to assist in the administration of the Plan and any other agents it deems advisable in carrying out the provisions of the Plan, including legal and actuarial counsel;

(g) To interpret and construe all terms, provisions, conditions and limitations of this Plan and to reconcile any inconsistency or supply any omitted detail that may appear in this Plan in such manner and to such extent, consistent with the general terms of this Plan, as the Committee shall deem necessary and proper to effectuate the Plan; and

(h) To make and enforce such rules and regulations for the administration of the Plan as are not inconsistent with the terms of the Plan.

8.5 Rules and Decisions : The Committee may adopt such rules and actuarial tables as it deems necessary, desirable or appropriate. All rules and decisions of the Committee shall be uniformly and consistently applied to all Employees in similar circumstances. The judgment of the Committee and each member thereof on any question arising hereunder shall be binding, final and conclusive on all parties concerned. When making a determination or calculation, the Committee shall be entitled to rely upon information furnished by an Employer, the legal counsel of an Employer, the Actuary for the Plan or the Trustee.

8.6 Committee Procedures : The Committee may act at a meeting or in writing without a meeting. The Committee shall elect one (1) of its members as chairman, appoint a secretary who may or may not be a member of the Committee, and shall advise the Trustee of such actions in writing. The secretary of the Committee shall keep a record of all meetings and forward all necessary communications to the Employers, the Trustee and the Actuary. The Committee may adopt such bylaws and regulations as it deems desirable for the conduct of its affairs. All decisions of the Committee shall be made by the vote of the majority including actions in writing taken without a meeting. A dissenting Committee member who, within a reasonable time after he has knowledge of any action or failure to act by the majority, registers his dissent in writing delivered to the other Committee members, the Employer and the Trustee shall not be responsible for any such action or failure to act.

8.7 Authorization of Benefit Payments : The Committee shall issue directions to the Trustee concerning all benefits which are to be paid from the Trust Fund pursuant to the provisions of the Plan, and warrants that all such directions are in accordance with this Plan. The Committee shall keep on file, in such manner as it may deem convenient or proper, all reports from the Trustee.

8.8 Payment of Expenses : All expenses incident to the administration, termination or protection of the Plan and Trust, including, but not limited to, actuarial, legal, accounting, Investment Manager and Trustee fees, shall be paid by the Trustee from the Trust Fund and, until paid, shall constitute a first and prior claim and lien against the Trust Fund.

8.9 Application and Forms for Pension : The Committee may require a Participant to complete and file with the Committee an application for Pension and all other forms approved by the Committee, and to furnish all pertinent information requested by the Committee. The Committee may rely on such information so furnished it, including the Participant’s current mailing address.

8.10 Indemnification of Committee : Except to the extent that such liability is created by ERISA, no Participant of the Committee shall be liable for any act or omission of any other member of the Committee, nor for any act or omission on his own part except for his own gross negligence or willful misconduct, nor for the exercise of any power or discretion in the performance of any duty assumed by him hereunder. The Company shall indemnify and hold harmless each member of the Committee from any and all claims, losses, damages, expenses (including counsel fees approved by the Committee) and liabilities (including any amounts paid in settlement with the Committee’s approval but excluding any excise tax assessed against any member or members of the Committee pursuant to the provisions of Section 4975 of the Code) arising from any act or omission of such member in connection with duties and responsibilities under the Plan, except when the same is judicially determined to be due to the gross negligence or willful misconduct of such member.

8.11 Annual Audit : If required by ERISA or requested by any Fiduciary, the Committee shall engage, on behalf of all Participants, an independent Certified Public Accountant who shall conduct an annual examination of any financial statements of this Plan and Trust Agreement and of other books and records of this Plan and Trust Agreement as the Certified Public Accountant may deem necessary to enable him to form and provide a written opinion as to whether the financial statements and related schedules required to be filed with the Department of Labor and furnished to each Participant are presented fairly and in conformity with generally accepted accounting principles applied on a basis consistent with that of the preceding Plan Year.

8.12 Funding Policy : The Committee shall, at a meeting duly called for such purpose, establish a funding policy and method consistent with the objectives of this Plan and the requirements of Title I of ERISA. The Committee shall meet at least annually to review such funding policy and method. In establishing and reviewing such funding policy and method, the Committee shall endeavor to determine the Plan’s short-term and long-term objectives and financial needs, taking into account the need for liquidity to pay benefits and the need for investment growth. All actions of the Committee taken pursuant to this Section 8.12 and the reasons therefor shall be recorded in the minutes of meetings of the Committee and shall be communicated to the Trustee, and any Investment Manager who may be managing a portion or all of the Trust Fund in accordance with provisions of the Trust Agreement.

8.13 Allocation and Delegation of Committee Responsibilities : Upon the approval of a majority of the members of the Committee, the Committee may (i) allocate among any of the members of the Committee any of the responsibilities of the Committee under the Plan and/or (ii) designate any person, firm or corporation that is not a member of the Committee to carry out any of the responsibilities of the Committee under the Plan. Any such allocation or designation shall be made pursuant to a written instrument executed by a majority of the members of the Committee.

ARTICLE IX

CONTRIBUTIONS TO THE PLAN

9.1 Participant Contributions : No contributions by Participants shall be required or permitted.

9.2 Employer Contributions : Each Employer shall make contributions for the benefit of its Participants in such amounts and at such times as determined by the board of directors of such Employer in accordance with a funding method and policy to be established by the Committee which will be consistent with Plan objectives. Annually, each Employer shall contribute at least the minimum amount required by the minimum funding standards of ERISA as determined by the Actuary. The provisions of this Section 9.2 shall be deemed the procedure for establishing and carrying out the funding policy and method of this Plan. All contributions made by Employers to the Trust Fund shall be irrevocable and shall be used to pay benefits under the Plan or to pay expenses of the Plan and Trust Fund. Notwithstanding anything in the Plan to the contrary, upon an Employer’s request, a contribution which was made by a mistake of fact, or conditioned upon initial qualification of the Plan or upon the deductibility of the contribution under Section 404 of the Code, shall be returned to such Employer within one (1) year after the payment of the contribution, the denial of the initial qualification or the disallowance of the deduction (to the extent disallowed), whichever is applicable.

9.3 Discontinuance or Suspension of Contributions : Upon a complete discontinuance of contributions by formal action of the board of directors of any Employer, or upon a suspension of Contributions to the Trust Fund by any Employer under such circumstances to constitute a complete discontinuance of contributions, the right of each affected Participant to his accrued benefit, to the extent then funded, shall be nonforfeitable and the Plan shall be terminated as to such Employer in accordance with Article XII as of the effective date of such discontinuance or such subsequent date selected by such Employer. If for any year an Employer fails to make a contribution to the Trust Fund in accordance with Section 9.2, and such failure constitutes a suspension of contributions which either affects benefits to be paid or made available hereunder or causes the unfunded past service cost at any time to exceed the unfunded past service cost as of January 1, 1991 (plus any additional past service costs thereafter added by amendment), then in either of such events the Employer shall notify the appropriate District Director of Internal Revenue regarding such suspension and the Pension Benefit Guaranty Corporation as required by ERISA Section 4043 and the regulations thereunder. During any such period of suspension, all other provisions of the Plan shall continue in full force and effect, other than the provisions required for contributions to the Trust Fund in accordance with Section 9.2. Upon a complete or partial termination of the Plan, the right of each affected Participant of the Employer to his accrued benefits to the date of such termination, to the extent then funded, shall be nonforfeitable, and the Employer shall promptly notify the appropriate District Director of Internal Revenue and the Pension Benefit Guaranty Corporation of such event. In the case of a partial termination, the provisions of this Section 9.3 shall apply only to the portion of the Plan so terminated.

9.4 Forfeitures Credited Against Employer’s Contributions : All credits arising as a result of more favorable interest, mortality, turnover or other experience than has been assumed in the actuarial determination of cost requirements, and all forfeitures by Participants or beneficiaries of Participants arising from any source whatsoever, shall be applied against the Employer’s contributions to be made pursuant to Section 9.2 hereof in subsequent years in accordance with a method of funding approved by the U.S. Treasury Department, and shall not be applied to increase the benefits that any Participant or the beneficiary of any Participant would otherwise receive under the Plan.

ARTICLE X

AMENDMENT OF THE PLAN

10.1 Right to Amend Reserved : The Company may, without the assent of any other party, amend, alter or modify this Plan at any time and from time to time in any manner except as hereinafter provided in Section 10.2.

10.2 Limitations on Right to Amend : No amendment to this Plan or the Trust Agreement (including a change in the actuarial basis for determining optional or early retirement benefits) shall be effective to the extent that it has the effect of decreasing a Participant’s accrued benefit. Notwithstanding the preceding sentence, a Participant’s accrued benefit may be reduced to the extent permitted under Section 412(c)(8) of the Code. For purposes of this paragraph, a Plan amendment which has the effect of (i) eliminating or reducing an early retirement benefit or a retirement type subsidy or (ii) eliminating an optional form of benefit, with respect to benefits attributable to service before the amendment, shall be treated as reducing accrued benefits. In the case of a retirement type subsidy, the preceding sentence shall apply only with respect to a Participant who satisfies (either before or after the amendment) the pre amendment conditions for the subsidy. In general, a retirement type subsidy is a subsidy that continues after retirement, but does not include a qualified disability benefit, a medical benefit, a social security supplement, a death benefit (including life insurance) or a plant shutdown benefit (that does not continue after retirement age). Furthermore, no amendment to the Plan shall have the effect of decreasing a Participant’s vested interest determined without regard to such amendment as of the later of the date such amendment is adopted or becomes effective.

If this Plan is amended and an effect of such amendment is to increase current liability (as defined in Code Section 401(a)(29)(E)) under the Plan for a Plan Year, and the funded current liability percentage of the Plan for the Plan Year in which the amendment takes effect is less than sixty percent (60%), including the amount of the unfunded current liability under the Plan attributable to the amendment, the amendment shall not take effect until the Employer (or any member of a controlled group which includes the Employer) provides security to the Plan. The form and amount of such security shall satisfy the requirements of Code Sections 401(a)(29)(B) and (C). Such security may be released provided the requirements of Code Section 401(a)(29)(D) are satisfied.

No amendment shall directly or indirectly reduce a Participant’s nonforfeitable vested percentage in his benefits under Section 5.5 unless each Participant having not less than three (3) years of Service is permitted to elect to have his nonforfeitable vested percentage in his benefits under Section 5.5 computed under the provisions of Section 5.5 without regard to the amendment. Such election shall be available during an election period which shall begin on the date such amendment is adopted and shall end on the latest of (i) the date sixty (60) days after such amendment is adopted, (ii) the date sixty (60) days after such amendment is effected, or (iii) the date sixty (60) days after such Participant is issued written notice of the amendment by the Committee or the Employer.

The Company specifically reserves the right, however, to make retroactive amendments as may be required by the Commissioner of the Internal Revenue Service to preserve this Plan as a qualified pension plan under Section 401(a) of the Code and to maintain the tax exempt status of its related Trust under Section 501(a) of the Code.

Effective as of October 1, 2008, no amendment shall take effect if such amendment has the effect of increasing the liabilities of the Plan by reason of any increase in benefits, the establishment of new benefits, any change in the rate of benefit accrual, or any change in the rate at which benefits vest under the Plan when the Plan’s adjusted funding target attainment percentage (as such term is defined in Section 436(j)(2) of the Code) is certified by the Plan’s enrolled actuary (or deemed under the Treasury regulations) to be (i) less than 80%, or (ii) would be less than 80% taking into account such amendment; provided, however, that the limitation in this paragraph shall not apply to an amendment that provides for an increase in benefits under a formula which is not based on Compensation if the rate of increase does not exceed the contemporaneous rate of increase in average wages of the Participants covered by such amendment. Except as otherwise provided by Section 436 of the Code or applicable Treasury regulations, the limitation provided in this paragraph shall cease to apply with respect to any Plan Year, effective as of the first day of such Plan Year (or, if later, the effective date of the amendment), if a participating company makes a contribution (in addition to any minimum required contribution under Section 430 of the Code) equal to: (i) if the Plan’s adjusted funding target attainment percentage is less than 80%, the amount of the increase in the Plan’s funding target (under Section 430 of the Code) that the Plan’s enrolled actuary certified is attributable to the amendment; or (ii) if the Plan’s adjusted funding target attainment percentage would be less than 80% taking into account the amendment, the amount sufficient to result in an adjusted funding target attainment percentage of 80%.

10.3 Form of Amendment : Each such amendment shall be evidenced by an instrument in writing of equal formality as this Plan, appropriately authorized by the Board of Directors executed by officers of the Company.

10.4 Merger of Plan with Another Pension Plan : In the event of any merger or consolidation of this Plan with any other pension plan, or in the event of a transfer of the assets or liabilities of this Plan to another pension plan, each Participant in the Plan shall be entitled to receive a benefit if the Plan were to terminate immediately after such merger, consolidation or transfer which is equal to or greater than the benefit he would have been entitled to receive immediately before such merger, consolidation or transfer if the Plan had then been terminated. In the event of any such merger, consolidation or transfer, the Committee shall report such event to the Pension Benefit Guaranty Corporation within thirty (30) days after the Committee first knew or had reason to know of such event.

ARTICLE XI

THE TRUSTEE AND THE TRUST FUND

11.1 Trustee : A Trustee has been appointed by the Company. Such Trustee and any successor Trustee shall serve at the pleasure of the Company and shall have such rights, duties and powers as are set forth in the Trust Agreement.

11.2 Trust Agreement : This Plan is a participating Plan under the Trust Agreement, known as the Cabot Oil & Gas Corporation Pension Plan Trust Agreement, effective January 1, 1991, providing for the administration of the Trust Fund by the Trustee. All the terms and conditions of the Trust Agreement, effective January 1, 1991, and as thereafter amended from time to time, are incorporated herein by reference to the extent not inconsistent herewith.

11.3 Benefits Paid Solely from Trust Fund : All benefits provided under the Plan shall be paid out of the Trust Fund. The Employers shall not be responsible or liable in any manner for payment of any such benefits, and all Participants shall look solely to the Trust Fund and to the adequacy thereof for the payment of any such benefits of any nature or kind which may at any time be payable hereunder, except to the extent, if any, that the Employers are liable to the Pension Benefit Guaranty Corporation under ERISA.

11.4 Trust Fund Applicable Only to Payment of Benefits : The Trust Fund shall be used and applied only to provide the benefits of the Plan in accordance with the provisions thereof. No part of the corpus or income of the Trust Fund will be used for, or diverted to, purposes other than for the exclusive benefit of Participants, retired Participants and their beneficiaries, or for the payment of reasonable expenses of the Plan, except as provided in Section 12.5.

11.5 Accounting by Trustee : The Trustee shall keep proper accounts of all investments, receipts, disbursements and other transactions effected by it hereunder, and all accounts, books and records relating thereto shall be open for inspection at all reasonable times by the Committee or by any other person designated by the Company, but nothing herein contained shall be construed to require the Trustee to maintain any record of the interests of the individual Participants in the Trust Fund. As of the close of each Plan Year (or more often, if requested by the Company), the Trustee shall prepare and furnish to the Committee, the Employers and the Actuary an annual valuation of the Trust Fund, containing a detailed statement of investments reflecting cost and market values, and a statement of receipts and disbursements of the Trust Fund and other transactions effected by it during such year.

11.6 Authorization to Protect Trustee : Any action by the Company or other Employer pursuant to any of the provisions of this Plan shall be evidenced by an appropriate written instrument or a resolution of its board of directors certified to the Trustee over the signature of its Secretary or Assistant Secretary under its corporate seal or by written instrument executed by any person authorized by said board of directors to take such action, and the Trustee shall be fully protected in acting in accordance with such written instrument or resolution so certified to it.

11.7 Exemption from Bond : The Trustee shall not be required to give bond or other security for the faithful performance of its duties hereunder unless otherwise required by law.

ARTICLE XII

TERMINATION OF THE PLAN

12.1 Right to Terminate Reserved : The Company and each other Employer has reserved the right to terminate this Plan with respect to its Employees at any time. Any such termination shall become effective when and as the Committee and the Trustee shall have received a written instrument authorizing such termination and executed by the Company or other Employer. If the Plan is terminated by fewer than all Employers, the Plan shall continue in effect for employees of the remaining Employers. Any termination (other than a partial termination which shall occur under circumstances set forth in Treasury Regulation Section 1.411(d) 2(b) or involuntary termination pursuant to ERISA Section 4042) must satisfy the requirements and follow the procedures outlined in ERISA Section 4041 for a “standard termination” or in ERISA Section 4042 for a “distress termination.” Upon a complete or partial termination of the Plan, each affected Participant’s Accrued Pension, based on his Benefit Service and Average Monthly Compensation prior to the date of such termination, shall become fully vested and nonforfeitable to the extent then funded. Any distribution made upon termination of the Plan shall be subject to the distribution limitations otherwise applicable under the Plan, specifically including the consent provisions of Section 5.6. Notwithstanding the foregoing, the Company has terminated the Plan with respect to all Employers and all Participants effective as of September 30, 2010.

12.2 Continuance with Successor Employer : Upon an Employer’s liquidation, bankruptcy, insolvency, sale, consolidation or merger to or with another organization that is not an Employer hereunder, in which such Employer is not the surviving company, all obligations of that Employer hereunder and under the Trust Agreement which have not theretofore been funded shall terminate automatically, and the Trust Fund assets attributable to such Employer shall be held or distributed as herein provided, unless the successor to that Employer assumes the duties and responsibilities of such Employer, by adopting this Plan and the Trust Agreement, or by establishment of a separate plan and trust to which the assets of the Trust Fund held on behalf of the employees of such Employer shall be transferred with the consent and agreement of that Employer. Upon the consolidation or merger of two or more of the Employers under this Plan with each other, the surviving Employer or organization shall automatically succeed to all the rights and duties under the Plan and Trust Agreement of the Employers involved and their shares of the Trust Fund shall be merged and thereafter be allocable to the surviving Employer or organization for its Employees and their beneficiaries. Notwithstanding the above provisions of this Section 12.2 to the contrary, not less than thirty (30) days prior to any such merger, consolidation or transfer of Trust Fund assets, the Committee shall file with the Commissioner of Internal Revenue the actuarial statement of valuation required by Section 6058(b) of the Code evidencing compliance with the requirements of Section 401(a)(12) of the Code and Section 10.4 of the Plan.

12.3 Liquidation of Trust Fund : Upon full termination of the Plan with respect to any Employer, a separation of the Trust Fund with respect to Participants of such Employer shall be made as of the effective date of such termination in accordance with the procedures set forth in Section 13.3. Thereafter, each Participant’s Accrued Pension based on his Benefit Service and Average Monthly Compensation prior to the date of termination, to the extent then funded and payable under the following provisions, shall become fully vested and the assets of the Trust Fund attributable to Participants of such terminated Employer shall be allocated, after provision is made for the expenses of liquidating the Trust Fund and of terminating the Plan, among Participants receiving or holding the following benefits in the following order:

(a) First, to benefits payable on the termination date:

(i) In the case of the benefit of a Participant or beneficiary which was in pay status as of the beginning of the three year period ending on the termination date of the Plan, to each such benefit, based on the provisions of the Plan (as in effect during the five year period ending on such date) under which such benefit would be the least, and

(ii) In the case of a retired Participant’s, a disabled Participant’s or a beneficiary’s benefit (other than a benefit described in subparagraph (i) above) which would have been in pay status as of the beginning of such three year period if the Participant had retired prior to the beginning of the three year period and if his benefits had commenced (in the normal form of pension under the Plan) as of the beginning of such period, to each such benefit based on the provisions of the Plan (as in effect during the five year period ending on such date) under which such benefit would be the least.

For purposes of subparagraph (i) of this paragraph (a), the lowest benefit in pay status during a three year period shall be considered the benefit in pay status for such period.

(b) Second:

(i) To all other benefits (if any) of individuals under the Plan guaranteed under Title IV Plan Termination Insurance of ERISA (determined without regard to Section 4022(b)(5) of ERISA), and

(ii) To the additional benefits (if any) which would be determined under subparagraph (i) above if Section 4022(b)(6) of ERISA did not apply.

For purposes of this paragraph (b), Section 4021 of ERISA shall be applied without regard to subsection (c) thereof.

(d) Fourth, to all other benefits under the Plan.

If the assets available for allocation under paragraph (a) or (b) above are insufficient to satisfy in full the benefits of all individuals which are described in such paragraph, the assets shall be allocated pro rata among individuals on the basis of the present value (as of the termination date) of their respective benefits described in such paragraph. If the assets available for allocation under paragraph (c) or (d) above are not sufficient to satisfy in full the benefits of individuals described in such paragraph, then:

(e) If this paragraph applies except as provided in subparagraph (B) below, the assets shall be allocated to the benefits of individuals described in paragraph (c) above on the basis of the benefits of individuals which would have been described in such paragraph (c) under the Plan as in effect at the beginning of the five year period ending on the date of Plan termination.

(f) If the assets available for allocation under subparagraph (A) are sufficient to satisfy in full the benefits described in such subparagraph (without regard to this subparagraph), then for purposes of subparagraph (A), benefits of individuals described in such subparagraph shall be determined on the basis of the Plan as amended by the most recent Plan amendment effective during such five year period under which the assets available for allocation are sufficient to satisfy in full the benefits of individuals described in subparagraph (A) and any assets remaining to be allocated under such subparagraph shall be allocated under subparagraph (A) on the basis of the Plan as amended by the next succeeding Plan amendment effective during such period.

12.4 Distribution of Trust Fund : Any distribution after full termination of the Plan may be made in whole or in part, to the extent that no discrimination in value results, in cash, securities or other assets in kind, or in annuity contracts, as the Committee, in its discretion, acting under the advice of the Actuary, shall determine; provided, however, that in no event shall a distribution be made in a form other than the Automatic Option if such distribution would have been made in such form had the Participant terminated his Service and commenced receiving his Pension immediately prior to the date on which the distribution pursuant to this Section is made. The benefits as apportioned pursuant to Section 12.3 above may be provided:

(a) By the continuation of the Trust Fund for the payment of all or such of the benefits as are within the limits prescribed by the Committee and acceptable by the Trustee;

(b) Through the purchase of annuities from one or more insurance companies with the amount of the benefit determined by a premium equal to the Actuarial Value of each Participant’s benefit;

(c) By distribution in a single sum of the Actuarial Value of each Participant’s benefit; provided, however, that the Participant may elect to receive the single sum (i) as a lump sum payment or (ii) as an immediate annuity in the form of a Single Life Annuity with no survivors or a Joint and Survivor Annuity that is a joint and 50 percent survivor level annuity that is the Actuarial Equivalent of the Participant’s single life annuity and with payments to continue after the death of the Participant at 50 percent, 75 percent or 100 percent of such benefit (according to his election); and

(d) By any combination of (a), (b) and (c). In making such distributions, any and all determinations, divisions, appraisals, apportionments and allotments so made shall be final and conclusive and shall not be subject to question by any person. Any annuity contract distributed by the Trustee to a Participant under subparagraph (b) above or under any other provision of this Plan shall bear on the face thereof a designation “Not Transferable,” and such annuity contract shall expressly provide that the contract may not be sold, assigned, discounted or pledged as collateral for a loan or as security for the performance of an obligation or for any other purpose to any person other than the issuer thereof. Notwithstanding the foregoing, the Employer or the Committee shall promptly advise the appropriate District Director of Internal Revenue and the Pension Benefit Guaranty Corporation of the termination and shall direct the Trustee to delay the final distribution to Participants until said District Director shall advise in writing that such termination does not adversely affect the previously qualified status of the Plan or the exemption from tax of the Trust under Section 401(a) or 501(a) of the Code and the period during which the Pension Benefit Guaranty Corporation (“PBGC”) may issue a notice of noncompliance in connection with the proposed termination has expired and either (i) the Committee has not received a notice of noncompliance or (ii) the PBGC and the Committee have agreed in writing that such distributions may be made.

12.5 Residual Amounts : In no event shall any Employer receive any amounts from the Trust Fund except that upon termination of the Plan, and notwithstanding any other provision of the Plan, an Employer shall receive such amounts, if any, as may remain in the Trust Fund because of erroneous actuarial computation as defined in U.S. Treasury Regulations and as determined by the Company in its sole discretion.

12.6 Limitations Imposed by Treasury Regulations upon Termination of Plan : In the event of the termination of the Plan, the benefit of any “highly compensated employee” or “highly compensated former employee” (each as defined in Section 414(q) of the Code and described further in Section 12.6(a) below) shall be limited to a benefit that is nondiscriminatory under Section 401(a)(4) of the Code and the Treasury regulations thereunder.

(a) Affected Highly Compensated Employees . For any Plan Year, the provisions of this Section 12.6 shall apply to the group of Participants composed of the top 25 “highly compensated employees” and “highly compensated former employees” having the greatest Compensation in the current or any prior Plan Year. The amount of the benefits payable for each Plan Year to any Participant subject to this Section 12.6 shall be limited to the payments that would be made to such Participant under (i) a single life annuity that is the actuarial equivalent of the Participant’s accrued Pension and other benefits (other than a social security supplement) to which he is entitled under the Plan, and (ii) any social security supplement to which the Participant is entitled under the Plan.

(b) Exception to Limits . The restrictions set forth in this Section 12.6 shall not apply if any of the following requirements is satisfied:

(i) After payment to the Participant of all benefits payable to him under the Plan the value of the Plan’s assets is at least one hundred ten percent (110%) of the value of the Plan’s “funding target” (as determined pursuant to Section 430(d)(1) of the Code), each valued as of the date reported on the Schedule B (or successor schedule thereto) to the most recent timely filed Form 5500 series annual return/report for the Plan;

(ii) The value of the benefits payable to the Participant is less than one percent (1%) of the value of the Plan’s “funding target” before distribution; or

(iii) The value of the benefits payable to the Participant does not exceed $5,000 (or such other amount prescribed by Section 411(a)(11)(A) of the Code).

In the event that Congress should provide by statute, or the Treasury Department or the Internal Revenue Service should provide by regulation or ruling, that the limitations provided for in this Section 12.6 are no longer necessary in order to meet the requirements for a qualified pension plan under the Code as then in effect, the limitations in this Section 12.6 shall become void and shall no longer apply without the necessity of amendment to this Plan.

ARTICLE XIII

ADOPTION OF PLAN BY OTHER ORGANIZATIONS

13.1 Procedure for Adoption : Any corporation or other organization with employees, now in existence or hereafter formed or acquired, which is not already an Employer under this Plan which is otherwise legally eligible, and, unless otherwise specifically provided, is an Affiliate, may, in the future, with the consent and approval of the Company, by formal resolution or decision of its own board or governing authority, adopt the Plan and the related Trust Agreement, for all or any classification of persons in its employment, and thereby, from and after the specified effective date become an “Employer” as defined in this Plan. Such adoption shall be effectuated by and evidenced by an adoptive instrument executed by the adopting organization and consented to by the Company and the Trustee. The adoption resolution or decision and the adoptive instrument may contain such specific changes and variations in Plan or Trust Agreement terms and provisions as may be acceptable to the Company and the Trustee. The adoption resolution or decision and the adoptive instrument shall become, as to such adopting organization and its employees, a part of this Plan as then amended and the related Trust Agreement. It shall not be necessary for the adopting organization to sign or execute the original or then amended Plan and Trust documents. The effective date of the Plan for any such adopting organization shall be that stated in such resolution or decision and the adoptive instrument, and from and after such effective date such adopting organization shall assume all the rights, obligations and liabilities of an individual Employer entity hereunder and under the Trust Agreement, and shall be included within the meaning of the term “Employer,” as herein defined. Such adopting corporation or other organization shall forthwith obtain a favorable determination letter from the appropriate District Director of Internal Revenue with respect to its participation in the Plan and Trust Agreement. The administrative powers and control of the Company, as provided in the Plan, including the sole right of amendment of the Plan and of appointment and removal of the Committee members, shall not be diminished by reason of the participation of any such adopting organization in the Plan and Trust. Any participating Employer may withdraw from the Plan and Trust at any time without affecting other Employers not withdrawing by complying with the provisions of the Plan and Trust Agreement. The Company may, in its absolute discretion, terminate an adopting Employer’s participation at any time when in its judgment such adopting Employer fails or refuses to discharge its obligations. Notwithstanding any provision in this Plan to the contrary, unless otherwise specifically provided, a corporation or other organization which has adopted this Plan and which is no longer a member of an affiliated service group, a controlled group or a group of trades or businesses of which the Company is a member shall no longer be an Employer under this Plan.

13.2 Effect of Adoption : The following special provisions shall apply to all Employers:

(a) An Employee shall be considered in continuous Service while regularly employed simultaneously or successively by one or more Employers.

(b) The transfer of a Participant from one Employer to another or to an Affiliate shall not be deemed a termination of Service.

13.3 Separation of the Trust Fund : A separation of the Trust Fund as to the interests therein of the Participants of any particular Employer may be made at the times and under the circumstances described in Section 12.3, 13.4 or 13.5. In such event, the Trustee shall set apart that portion of the Trust Fund which the Committee shall certify to the Trustee is the equitable share of such Participants pursuant to a valuation and allocation of the Trust Fund made as of the date when such separation of the Trust Fund shall be effective. Such portions of the Trust Fund may in the Trustee’s discretion be set apart in cash or in kind out of the properties of the Trust Fund. That portion of the Trust Fund so set apart shall continue to be held by the Trustee as though such Employer had entered into the Trust Agreement as a separate trust agreement with the Trustee. Such Employer may in such event designate a new trustee of its selection to act as trustee under the Trust Agreement, and shall thereupon be deemed to have adopted the Plan as its own separate plan and shall subsequently have all the powers of amendment or modification of the Plan as are reserved herein to the Company.

13.4 Voluntary Separation : If any Employer shall desire to separate its interest in the Trust Fund, it may request such a separation in a notice in writing to the Company and the Trustee. Such separation must be approved by the Board of Directors shall then be made as of any specified date after service of such notice, and such separation shall be accomplished in the manner set forth in Section 13.3 above.

13.5 Approval of Amendment : Any amendment of the Plan or the Trust Agreement by the Company pursuant to Article X shall be promptly delivered to each other Employer who will be deemed to have consented to such amendment unless it, within thirty (30) days after receipt of the amendment, rejects such amendment and seeks a separation of its interest in the Trust Fund in accordance with the provisions of Section 13.3 hereof.

ARTICLE XIV

MISCELLANEOUS

14.1 Interest on Deferred Payments : In the event that any portion of a lump sum benefit provided and payable under this Plan is not paid within sixty (60) days after the termination of employment, Disability or death of a Participant, whichever is applicable, such unpaid portion shall earn interest until paid at a eight and one half percent (8 ¹ / 2 %) rate of interest.

14.2 Plan Not an Employment Contract : The adoption and maintenance of the Plan shall not be deemed to constitute a contract between an Employer and any Participant, and shall not be deemed to be consideration for, inducement to or a condition of employment of any person. Nothing herein contained shall be construed to give any Participant the right to be retained in the employment of an Employer or to interfere with the right of an Employer to terminate the employment of any Participant at any time.

14.3 Controlling Law : Subject to the provisions of ERISA, as the same may be amended from time to time, which may be applicable and provide to the contrary, this Plan shall be construed, regulated and administered under the laws of the State of Texas.

14.4 Invalidity of Particular Provisions : In the event any provision of this Plan shall be held illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining provisions of this Plan but shall be fully severable, and this Plan shall be construed and enforced as if said illegal or invalid provisions had never been inserted herein.

14.5 Non Alienability of Rights of Participants : Except as otherwise provided below and with respect to certain judgments and settlements pursuant to Section 401(a)(13) of the Code, no benefit which shall be payable out of the Trust Fund to any person (including a Participant or Beneficiary) shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance or charge, and any attempt to anticipate, alienate, sell, transfer, assign, pledge, encumber or charge the same shall be void; and no such benefit shall in any manner be liable for, or subject to, the death, contracts, liabilities, engagements or torts of any person, and the same shall not be recognized by the Trustee, except to the extent as may be required by law.

This provision shall not apply to a “qualified domestic relations order” defined in Code Section 414(p), and those other domestic relations orders permitted to be so treated by the Committee under the provisions of the Retirement Equity Act of 1984. Further, to the extent provided under a “qualified domestic relations order,” a former spouse of a Participant shall be treated as the Spouse or Surviving Spouse for all purposes of the Plan. If the Committee receives a qualified domestic relations order with respect to a Participant, the Committee may authorize the immediate distribution of the amount assigned to the Participant’s former spouse, to the extent permitted by law, from the Participant’s Accounts.

14.6 Copy Available to Participants : A copy of this Plan and the Trust Agreement and of any and all future amendments thereto shall be available to Participants and their beneficiaries for inspection at all reasonable times.

14.7 Evidence Furnished Conclusive : Each Employer, the Committee and any person or persons involved in the administration of the Plan shall be entitled to rely upon any certification, statement or representation made or evidence furnished by an Employee, Participant or beneficiary with respect to his age, or other facts required to be determined under any of the provisions of the Plan, and shall not be liable on account of the payment of any monies or the doing of any act or failure to act in reliance thereon. Any such certification, statement, representation or evidence, upon being duly made or furnished, shall be conclusively binding upon such Employee, Participant or beneficiary but not upon an Employer, the Committee or any other person or persons involved in the administration of the Plan. Nothing herein contained shall be construed to prevent any of such parties from contesting any such certification, statement, representation or evidence or to relieve the Employee, Participant or beneficiary from the duty of submitting satisfactory proof of his age or such other fact.

14.8 Unclaimed Benefits : If at, after or during the time when a benefit hereunder is payable to any Participant, Joint Pensioner or other distributee, the Committee, upon request of the Trustee, or in its own instance, shall mail by registered or certified mail to such Participant, Joint Pensioner or other distributee at his last known address a written demand for his current address or for satisfactory evidence of his continued life, or both, and if such Participant, Joint Pensioner or other distributee shall fail to furnish the same to the Committee within two (2) years from the mailing of such demand, the Committee may, in its sole discretion, determine that such Participant, Joint Pensioner or other distributee has forfeited his right to such benefit and declare such benefit, or any unpaid portion thereof, terminated as if the death of the Participant (with no surviving Joint Pensioner or other distributee) had occurred on the date of the last payment made thereon, or the date such Participant, Joint Pensioner or other distributee first became entitled to receive benefit payments, whichever is later; provided, however, that such forfeited benefit shall be reinstated if a claim for the same is made by the Participant, Joint Pensioner or other distributee at any time thereafter.

14.9 Name and Address Changes : Each Participant and each Joint Pensioner or other beneficiary of a deceased Participant shall at all times be responsible for notifying the Committee of any change in his name or address. If any check in payment of a benefit hereunder (which was mailed to the last address of the payee as shown on the Committee’s records) is returned unclaimed, further payments shall be discontinued until the Committee directs otherwise.

14.10 Facility of Payment : If the Committee receives satisfactory evidence that any person entitled to make any election or to receive any payment of a benefit or installment thereof hereunder is (at the time such election or payment is to be made) physically, mentally or legally incompetent to make such election or to receive such benefit and to give a valid receipt therefor and that an individual or institution is then maintaining or has custody of such person and that no guardian, committee or other representative of the estate of such person has been duly appointed, the Committee may make such election in its complete and absolute discretion or may authorize payment of such benefit to such individual or institution maintaining or having the custody of such person, and the receipt of such individual or institution shall be a valid and complete discharge for the payment of such benefit or installment thereof. Deposit to the credit of a Participant or beneficiary in any bank or trust company shall be deemed payment into his hands.

14.11 Payments in Satisfaction of Claims of Participants : Any payment or distribution to any Participant or his legal representative, Joint Pensioner or beneficiary in accordance with the provisions of this Plan shall be in full satisfaction of all claims under the Plan against the Trust Fund, the Committee, the Trustee and the Employer.

14.12 Headings for Convenience Only : The headings and subheadings in this Plan are inserted for convenience and reference only and are not to be used in construing this Plan or any provision herein.

ARTICLE XV

LIMITATION ON BENEFITS

Notwithstanding any provision of this Plan to the contrary, the total Annual Benefit received by an Employee shall be subject to the following limitations:

15.1 Limitations on Benefits .

In accordance with Treasury Regulation § 1.415(a)-1(d)(3), the Plan incorporates by reference the limitations on benefits under Code Section 415 and as provided under Treasury Regulation § 1.415(b)-1 et seq. (as may be revised or amended from time to time by the Internal Revenue Service), including, but not limited to, Treasury Regulation § 1.415(f)-1. Unless otherwise provided in this Section, the default rules under Code Section 415 Treasury Regulations shall apply with respect to the limitations under this Section.

Notwithstanding any provision of this Plan to the contrary, the Annual Benefit otherwise accrued by or payable to a Participant under the Plan at any time shall not exceed, and shall be limited to (or the rate of accrual reduced to), the “Maximum Permissible Benefit,” which is the lesser of:

(i) $160,000, as adjusted for cost of living increases pursuant to Code Section 415(d) and Treasury Regulation § 1.415(d)-1(a) (the “Dollar Limit”); or

(ii) 100% of the Participant’s average Compensation for the period of the Participant’s High-3 Years of Service, as adjusted pursuant to Code Section 415(d) (the “Percentage Limit”).

In no event shall an Annual Benefit exceeding the above limits be accrued, distributed, or otherwise payable in any optional form of benefit, including the normal form of benefit, at any time from the Plan (or from an annuity contract that will make distributions to a Participant on behalf of the Plan or from an annuity contract distributed under the Plan).

In the event a Participant’s Annuity Starting Date occurs before he attains age 62 or after he attains age 65, his Maximum Permissible Benefit shall be adjusted in accordance with the provisions of Treasury Regulation § 1.415(b)-1(d) or (e), respectively, and, if applicable, under Treasury Regulation § 1.415(b)-1(h).

The Annual Benefit (without regard to the age at which benefits commence) payable with respect to a Participant does not exceed the Dollar Limit if (i) the benefits (other than benefits not taken into account in the computation of the Annual Benefit under the rules of Treasury Regulation § 1.415(b)-1(b) or (c)) payable with respect to a Participant under the Plan and all other defined benefit plans of the Employer do not in the aggregate exceed $10,000 for the Limitation Year or for any prior Limitation Year (as computed in accordance with Treasury Regulation § 1.415(b)-1(f)(2) and subject to adjustment for participation of less than 10 years); and (ii) the Employer (or a predecessor employer) has not at any time maintained a defined contribution plan in which the Participant participated.

If a Participant has less than 10 years of participation in the Plan, the Dollar Limit, Percentage Limit and the $10,000 amount described above shall be multiplied by a fraction, the numerator of which is the number of years (or part thereof, but not less than one year) of participation in the Plan, and the denominator of which is 10, in accordance with Treasury Regulation § 1.415(b)-1(g).

To the extent a Participant’s Annual Benefit for a Limitation Year exceeds the Participant’s Maximum Permissible Benefit, such result shall be corrected in accordance with procedures available under the Internal Revenue Service’s Employee Plans Compliance Resolution System in effect at the time of the correction.

For purposes of this Section, the following terms shall have the following meanings:

(a) Annual Benefit : The benefit that is payable in the form of a straight life annuity (with no ancillary benefits), as defined in Treasury Regulation § 1.415(b)-1(b). In the event that a Participant’s benefit is payable in a form other than a straight life annuity, his Annual Benefit shall be the benefit payable in the form of the straight life annuity payable on the first day of each month that is actuarially equivalent to the benefit payable in such other form, determined under the rules of Treasury Regulation § 1.415(b)-1(c) and, if applicable, under Treasury Regulation § 1.415(b)-1(h). The actuarial equivalent of a straight life annuity (A) for a form of benefit that is not subject to Section 417(e)(3) of the Code shall be computed using the following assumptions, whichever provides the greater equivalent annual benefit (1) a 5% interest rate assumption and the mortality table used for such form of benefit specified in Section 1.1 of the Plan for that Annuity Starting Date and (2) the interest rate and mortality table (or other tabular factor) specified in Section 1.1 of the Plan; and (B) for a form of benefit that is subject to Section 417(e)(3) of the Code shall be computed using either (I) the “applicable interest rate” under Section 417(e)(3) of the Code (“Applicable Interest Rate”) and the “applicable mortality table” under Section 417(e)(3) of the Code (“Applicable Mortality Table”) for adjusting benefits in the same form; (II) a 5.5% interest rate assumption and the Applicable Mortality Table; or (III) the Applicable Interest Rate and the Applicable Mortality Table, divided by 1.05, whichever provides the greatest annual amount.

In no event shall a Participant’s Annual Benefit include the benefit attributable to employee contributions or rollover contributions (as described in Code Sections 401(a)(31), 402(c)(1), 403(a)(4), 403(b)(8), 408(d)(3), and 457(e)(16)), determined in accordance with the rules under Treasury Regulation § 1.415(b)-1(b)(1)(2). In the event that the Plan includes benefits transferred to the Plan from another defined benefit plan, the treatment of such transferred benefits shall be determined in accordance with the provisions of Treasury Regulation § 1.415(b)-1(b)(3).

If a Participant has or will have distributions under the Plan commencing on more than one annuity starting date, the limitations under Code Section 415 must be satisfied as of each of the annuity starting dates, taking into account the benefits that have been or will be provided at all of the annuity starting dates, in accordance with Treasury Regulation § 1.415(b)-1(b)(1)(iii). In the event the Plan is terminated (i) with sufficient assets for the payment of benefit liabilities of all Participants and a Participant has not yet commenced benefits under the Plan, for purposes of satisfying Code Section 415(b) with respect to a Participant, the requirements of Treasury Regulation § 1.415(b)-1(b)(5)(i) must be satisfied; or (ii) without sufficient assets for the payment of benefit liabilities of all Participants, for purposes of satisfying Code Section 415(b) with respect to a Participant, the requirements of Treasury Regulation § 1.415(b)-1(b)(5)(ii) must be satisfied.

(b) Compensation : For purposes of this Section, Compensation shall

(i)

include :

(1)

Wages, salaries, fees for professional services and other amounts received (without regard to whether or not an amount is paid in cash) for personal services actually rendered in the course of employment with the Employer maintaining the Plan to the extent that such amounts are includable in gross income (or to the extent amounts that would have been received and includible in gross income but for an election by the Participant under Code Sections 125(a), 132(f)(4), 402(e)(3), 402(h)(1)(B), 402(k) or 457(b)), including, but not limited to, commissions paid to salesmen, compensation for services on the basis of a percentage of profits, commissions on insurance premiums, tips, bonuses, fringe benefits and reimbursements or other expense allowances under a nonaccountable plan as described in Treasury Regulation § 1.62-2(c);

(2)

Amounts described in Code Section 104(a)(3), 105(a), or 105(h), but only to the extent that these amounts are includible in the gross income of the Participant;

(3)

Amounts paid or reimbursed by the Employer for moving expenses incurred by a Participant, but only to the extent that at the time of the payment it is reasonable to believe that these amounts are not deductible by the Participant under Code Section 217;

(4)

The value of a nonstatutory option (which is an option other than a statutory option as defined in Treasury Regulation § 1.421-1(b)) granted to a Participant by the Employer, but only to the extent that the value of the option is includible in the gross income of the Participant for the taxable year in which granted;

(5)

The amount includible in the gross income of a Participant upon making the election described in Code Section 83(b); and

(6)

Amounts that are includible in the gross income of a Participant under the rules of Code Section 409A or 457(f)(1)(A) or because the amounts are constructively received by the Participant;

and (ii) exclude :

(1)

Contributions (other than elective contributions described in Code Sections 402(e)(3), 408(k)(6), 408(p)(2)(A)(i) or 457(b)) made by the Employer to a plan of deferred compensation (including a simplified employee pension described in Code Section 408(k) or a simple retirement account described in Code Section 408(p), whether or not qualified) to the extent the contributions are not included in the gross income of the Participant for the taxable year in which contributed, and any distributions from a plan of deferred compensation (whether or not qualified) regardless of whether such amounts are includable in the gross income of the Participant when distributed;

(2)

Amounts realized from the exercise of a nonstatutory option (which is an option other than a statutory option as defined in Treasury Regulation § 1.421-1(b)) or when restricted stock or other property held by a Participant becomes freely transferable or is no longer subject to a substantial risk of forfeiture under Code Section 83 and the Treasury Regulations thereunder;

(3)

Amounts realized from the sale, exchange or other disposition of stock acquired under a statutory stock option (within the meaning of Treasury Regulation § 1.421-1(b));

(4)

Other amounts which receive special tax benefits, such as, for example, premiums for group-term life insurance, to the extent such amounts are not includible in the gross income of the Participant and are not salary reduction amounts under Code Section 125; and

(5)

Other items of remuneration that are similar to the items listed above in clauses (ii)(1) through (4).

In addition to the foregoing, Compensation included for the Limitation Year in accordance with the timing rules under the provisions in Treasury Regulation § 1.415(c)-2(e)(1), includes:

(1)

Amounts paid after a Participant’s severance from employment for services during the Participant’s regular working hours or outside the Participant’s regular working hours (such as overtime or shift differential), commissions, bonuses, or other similar payments if (1) such amount would have been paid to the Participant prior to his severance from employment if he had continued in employment with the Employer (that has adopted the Plan) and (2) such amount is paid by the later of 2 ¹ / 2 months after the Participant’s severance from employment with the Employer or the end of the Limitation Year that includes the date of such severance from employment;

(2)

Amounts earned, but not paid, during a Limitation Year solely because of the timing of the pay periods, provided that such amounts are (1) paid during the first few weeks of the next Limitation Year, (2) included on a uniform and consistent basis with respect to all similarly situated Employees, and (3) not included in more than one Limitation Year; and

The foregoing notwithstanding, for purposes of this Section, Compensation shall not exceed the limitation under Code Section 401(a)(17)(A), as adjusted for cost-of-living increases pursuant to Code Section 401(a)(17)(B).

(c) Employer : The Company and any other Employer that adopts this Plan; provided, however, that in the case of a group of employers which constitutes a controlled group of corporations (as defined in Section 414(b) of the Code as modified by Section 415(h)) or which constitutes trades and businesses (whether or not incorporated) which are under common control (as defined in Section 414(c) as modified by Section 415(h)) or an affiliated service group (as defined in Section 414(m)), all such employers shall be considered a single employer for purposes of applying the limitations of this Section for any portion of a Limitation Year during which such employers were so controlled or affiliated.

(d) High-3 Years of Service : The average Compensation for the three consecutive years of Service (or, if the Participant has less than three consecutive years of Service, the Participant’s longest consecutive period of Service, including fractions of years, but not less than one year) with the Employer that produces the highest average. In the case of a Participant who is rehired by the Employer after a severance from employment, the Participant’s High-3 Years of Service shall be calculated by excluding all years for which the Participant performs no services for and receives no Compensation from the Employer (the break period) and by treating the years immediately preceding and following the break period as consecutive.

(e) Limitation Year : A 12-consecutive month period beginning on January 1st.

This Section shall be effective for Limitation Years commencing on and after January 1, 2008, except as otherwise provided herein. The application of the provisions of this Section shall not cause the Maximum Permissible Benefit for any Participant to be less than the Participant’s accrued benefit under the Plan as of the end of the last Limitation Year beginning before July 1, 2007 under provisions of the Plan that were both adopted and in effect before April 5, 2007.

ARTICLE XVI

TOP-HEAVY PLAN REQUIREMENTS

16.1 General Rule : For any Plan Year for which this Plan is a Top-Heavy Plan, as defined in Section 16.7, any other provisions of this Plan to the contrary notwithstanding, this Plan shall be subject to the provisions of this Article XVI.

16.2 Vesting Provisions : Each Participant who has completed an Hour of Service after the Plan becomes top heavy and while the Plan is top heavy and who has completed the Vesting Service specified in the following table shall be vested in his accrued benefit under this Plan at least as rapidly as is provided in the following schedule (but in any event no later than in accordance with Article IV):


Vesting Service		Vested Percentage
Less than 2 years		0%
2 but less than 3 years		20%
3 but less than 4 years		40%
4 but less than 5 years		60%
5 years or more		100%

If an account becomes vested by reason of the application of the preceding schedule, it may not thereafter be forfeited by reason of re-employment after retirement pursuant to a suspension of benefits provision, by reason of withdrawal of any mandatory employee contributions to which Employer contributions were keyed, or for any other reason. If the Plan subsequently ceases to be top heavy, the preceding schedule shall continue to apply with respect to any Participant who had at least three years of service (as defined in Treasury Regulation Section 1.411(a)-8T(b)(3)) as of the close of the last year that the Plan was top heavy. For all other Participants, the non-forfeitable percentage of their accrued benefit prior to the date the Plan ceased to be top heavy shall not be reduced, but future increases in the non-forfeitable percentage shall be made only in accordance with Article IV.

16.3 Minimum Benefit Provisions : Each Participant who is a Non-Key Employee, as defined in Section 16.7, shall be entitled to an accrued benefit in the form of a single life annuity (with no ancillary benefits) beginning at his Normal Retirement Date, that shall not be less than his average annual Participant’s Compensation, within the meaning of Section 415 of the Code, for years in the Testing Period multiplied by the lesser of: (a) 2% multiplied by the number of years of Top-Heavy Service or (b) 20%. A Non-Key Employee may not fail to receive a minimum benefit because of a failure to receive a specified minimum amount of Compensation or a failure to make mandatory employee or elective contributions.

“Testing Period” means, with respect to a Participant, the period of consecutive years of Top-Heavy Service, not exceeding five, during which the Participant had the greatest aggregate compensation, within the meaning of Section 415 of the Code, from the Employer. “Top-Heavy Service” means his vesting service credited under Section 2.1. Top-Heavy Service shall not include any vesting service before January 1, 1984 or any vesting service that begins after the close of the last Plan Year in which the Plan was a Top-Heavy Plan. Years before and after such excluded periods shall be considered consecutive for purposes of determining the Testing Period.

For purposes of satisfying the minimum benefit requirements of Section 416(c)(1) of the Code and the Plan, in determining Years of Service with the Employer, any service with the Employer shall be disregarded to the extent that such service occurs during a Plan Year when the Plan benefits (within the meaning of Section 410(b) of the Code) no Key Employee or former Key Employee.

16.4 Limitation on Compensation : The annual Compensation of a Participant taken into account under this Article XVI and under Section 1.12 for purposes of computing benefits under this Plan shall not exceed $220,000 for any Plan Year (unless adjusted in the same manner as permitted under Code Section 415(d)). Such amount shall be adjusted automatically for each Plan Year to the amount prescribed by the Secretary of the Treasury or his delegate pursuant to regulations for the calendar year in which such Plan Year commences.

16.5 Coordination With Other Plans : If another qualified employee benefit plan is maintained by a Considered Company which provides contributions or benefits on behalf of Participants in this Plan, such other plan shall be treated as a part of this Plan pursuant to applicable principles prescribed by U.S. Treasury Regulations or applicable IRS rulings (such as Revenue Ruling 81-202 or any successor ruling) to determine whether this Plan satisfies the requirements of Sections 16.2, 16.3 and 16.4 and to avoid inappropriate omissions or inappropriate duplication of minimum contributions. Such determination shall be made, upon the advice of counsel, by the Committee.

In the event a Participant is covered by a defined benefit plan which is top heavy pursuant to Section 416 of the Code, a comparability analysis (as prescribed by Revenue Ruling 81-202 or any successor ruling) shall be performed in order to establish that the plans are providing benefits at least equal to the defined benefit minimum.

16.6 Distributions to Certain Key Employees : Notwithstanding any provision of this Plan to the contrary, the entire interest in this Plan of each Participant who is a “5% owner” (as described in Section 416(i)(1) of the Code determined with respect to the Plan Year ending in the calendar year in which such individual attains age 70 ¹ / 2 ) shall be distributed to such Participant not later than the first day of April following the calendar year in which such individual attains age 70 ¹ / 2 .

16.7 Determination of Top-Heavy Status : The Plan shall be a Top-Heavy Plan for any Plan Year if, as of the Determination Date, the present value of the cumulative accrued benefits under the Plan (determined as of the Valuation Date) for Participants (including former Participants) who are Key Employees exceeds 60% of the present value of the cumulative accrued benefits under the Plan for all Participants (including former Participants) or, if this Plan is required to be in an Aggregation Group, any such Plan Year in which such Group is a Top-Heavy Group. In determining Top-Heavy status, if an individual has not performed one Hour of Service for any Considered Company at any time during the one-year period ending on the Determination Date, any accrued benefit for such individual and the aggregate accounts of such individual shall not be taken into account. The accrued benefit of any employee (other than a Key Employee) shall be determined under (a) the method, if any, that uniformly applies for accrual purposes under all plans maintained by the Aggregation Group or (b) if there is no such method, as if such benefit accrued not more rapidly than the slowest accrual rate permitted under the fractional accrual rate of Code Section 411(b)(1)(C).

For purposes of this Section, the capitalized words have the following meanings:

(a) “Aggregation Group” means the group of plans, if any, that includes both the group of plans that is required to be aggregated and the group of plans that is permitted to be aggregated. The group of plans that is required to be aggregated (the “required aggregation group”) includes:

(i) Each plan of a Considered Company in which a Key Employee is a participant, including collectively bargained plans; and

(ii) Each other plan, including collectively bargained plans, of a Considered Company which enables a plan in which a Key Employee is a participant to meet the requirements of either Code Section 401(a)(4) or 410.

(b) The group of plans that is permitted to be aggregated (the “permissive aggregation group”) includes the required aggregation group and any plan that is not part of the required aggregation group that the Committee certifies as constituting a plan within the permissive aggregation group. Such plans may be added to the permissive aggregation group only if, after the addition, the aggregation group as a whole continues to meet the requirements of both Code Sections 401(a)(4) and 410.

(d) “Determination Date” means for any Plan Year the last day of the immediately preceding Plan Year or in the case of the first Plan Year of the Plan, Determination Date means the last day of such Plan Year.

(e) “Key Employee” means any Employee or former Employee (including any deceased Employee) who at any time during the Plan Year that includes the Determination Date was an officer of a Considered Company having annual compensation greater than $130,000 (as adjusted under Section 416(i)(1) of the Code for Plan Years beginning after December 31, 2002), a 5-percent owner of a Considered Company, or a 1-percent owner of a Considered Company having annual compensation of more than $150,000. For this purpose, annual compensation means compensation within the meaning of Section 415(c)(3) of the Code. The determination of who is a Key Employee will be made in accordance with Section 416(i)(1) of the Code and the applicable regulations and other guidance of general applicability issued thereunder.

(f) A “Non-Key Employee” means any Participant (and any Beneficiary of a Participant) who is not a Key Employee.

(g) “Top-Heavy Group” means the Aggregation Group, if, as of the applicable Determination Date, the sum of the present value of the cumulative accrued benefits for Key Employees under all defined benefit plans included in the Aggregation Group plus the aggregate of the accounts of Key Employees under all defined contribution plans included in the Aggregation Group exceeds 60% of the sum of the present value of the cumulative accrued benefits for all employees, excluding former Key Employees as provided in paragraph (i) below, under all such defined benefit plans plus the aggregate accounts for all employees, excluding former Key Employees as provided in paragraph (i) below, under all such defined contribution plans. In determining Top-Heavy status, if an individual has not performed one Hour of Service for any Considered Company at any time during the one-year period ending on the Determination Date, any accrued benefit for such individual and the aggregate accounts of such individual shall not be taken into account. If the Aggregation Group that is a Top-Heavy Group is a permissive aggregation group, only those plans that are part of the required aggregation group will be treated as Top-Heavy Plans. If the Aggregation Group is not a Top-Heavy Group, no plan within such group will be a Top-Heavy Plan.

In determining whether this Plan constitutes a Top-Heavy Plan, the Committee (or its agent) will make the following adjustments:

(i) When more than one plan is aggregated, the Committee shall determine separately for each plan as of each plan’s Determination Date the present value of the accrued benefits (for this purpose using the actuarial assumptions set forth in the applicable plan, and if such assumptions are not set forth in the applicable plan, using the assumptions set forth in this Plan) or account balance. The results shall then be aggregated by adding the results of each plan as of the Determination Dates for such plans that fall within the same calendar year.

(ii) The present values of accrued benefits and the amounts of account balances of an Employee as of the Determination Date shall be increased by the distributions made with respect to the Employee under the Plan and any plan aggregated with the Plan under Section 416(g)(2) of the Code during the 1-year period ending on the Determination Date. The preceding sentence shall also apply to distributions under a terminated plan which, had it not been terminated, would have been aggregated with the Plan under Section 416(g)(2)(A)(i) of the Code. In the case of a distribution made for a reason other than severance from employment, death, or disability, this provision shall be applied by substituting “5-year period” for “1-year period.”

The accrued benefits and accounts of any individual who has not performed services for a Considered Company during the 1-year period ending on the Determination Date shall not be taken into account.

(iii) Further, in making such determination, such present value or such account shall include any rollover contribution (or similar transfer) as follows:

(A) If the rollover contribution (or similar transfer) is initiated by the employee and made to or from a plan maintained by another Considered Company, the plan providing the distribution shall include such distribution in the present value of such account; the plan accepting the distribution shall not include such distribution in the present value of such account unless the plan accepted it before December 31, 1983.

(B) If the rollover contribution (or similar transfer) is not initiated by the employee or made from a plan maintained by another Considered Company, the plan accepting the distribution shall include such distribution in the present value of such account, whether the plan accepted the distribution before or after December 31, 1983; the plan making the distribution shall not include the distribution in the present value of such account.

(iv) In any case where an individual is a Non-Key Employee with respect to an applicable plan but was a Key Employee with respect to such plan for any prior Plan Year, any accrued benefit and any account of such Employee shall be altogether disregarded. For this purpose, to the extent that a Key Employee is deemed to be a Key Employee if he met the definition of Key Employee within any of the four preceding Plan Years, this provision shall apply following the end of such period of time.

(h) “Valuation Date” means for purposes of determining the present value of an accrued benefit as of the Determination Date the date determined as of the most recent Valuation Date which is within a 12-month period ending on the Determination Date. For the first plan year of a plan, the accrued benefit for a current employee shall be determined either (i) as if the individual terminated service as of the Determination Date, or (ii) as if the individual terminated service as of the Valuation Date, but taking into account the estimated accrued benefit as of the Determination Date. The Valuation Date shall be determined in accordance with the principles set forth in Q.&A. T-25 of Treasury Regulations Section 1.416-1.

(i) For purposes of this Article, “Compensation” shall have the meaning given to it in Section 15.1(b) of the Plan.

IN WITNESS WHEREOF, Cabot Oil & Gas Corporation has executed these presents as evidenced by the signatures of its duly authorized officers, in a number of copies, all of which shall constitute but one and the same instrument, which may be sufficiently evidenced by any such executed copy hereof, this day of September, 2010, but effective as of September 30, 2010.


CABOT OIL & GAS CORPORATION

By		/s/ Abraham Garza
		Vice President

ATTEST:


/s/ Lisa A. Machesney

[SEAL]

THE STATE OF TEXAS		§

		§

COUNTY OF HARRIS		§

BEFORE ME, the undersigned authority, on this day personally appeared Abraham Garza , Lisa A. Machesney of CABOT OIL & GAS CORPORATION, known to me to be the person and officer whose name is subscribed to the foregoing instrument, and acknowledged to me that the same was the act of the said CABOT OIL & GAS CORPORATION, and that he executed the same as the act and deed of such limited partnership for the purposes and consideration therein expressed and in the capacity therein stated.

GIVEN UNDER MY HAND AND SEAL OF OFFICE this 30th day of September , 2010.

/s/ L A Pickering

Notary Public, State of Texas

Exhibit 10.23(a)

CABOT OIL & GAS CORPORATION SAVINGS INVESTMENT PLAN

(As Amended and Restated Effective January 1, 2009)

First 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 provide for discretionary profit sharing contributions, to authorize the Plan to accept a direct rollover to a Member’s account of any eligible distribution to such Member from the Cabot Oil & Gas Corporation Pension Plan, to remove the Cabot Corporation Common Stock Fund and to make certain changes required by the Heroes Earnings Assistance and Relief Tax Act of 2008;

NOW, THEREFORE, having reserved the right to amend the Plan pursuant to Section 10.4 thereof, the Company hereby amends the Plan, effective, unless otherwise provided below, as of October 1, 2010, as follows:

1. Section 1.21 of the Plan is hereby amended, in its entirety, to read as follows:

“1.21 Employer Contribution Account : The account maintained for a Member to record his share of the Contributions of his Employer and adjustments relating thereto. This account shall include the following sub-accounts, to the extent applicable: (a) the Matching Contribution Sub-Account, which shall reflect Matching Contributions made on the Member’s behalf; and (b) the Discretionary Profit Sharing Contribution Sub-Account, which shall reflect Discretionary Profit Sharing Contributions made on the Member’s behalf.”

2. Section 1.43 of the Plan is hereby amended, in its entirety, as follows:

“1.43 Rollover Account : The separate sub-account established and maintained on behalf of a Member or Beneficiary to reflect his interest in the Trust Fund

attributable to Rollover Contributions. The Committee, in its sole discretion, may choose to establish such sub-accounts within a Member’s or Beneficiary’s Rollover Account as the Committee deems appropriate.”

3. Section 1.44 of the Plan is hereby amended, in its entirety, to read as follows:

“1.44 Rollover Contribution : Any amount contributed to the Plan by an Employee or Member pursuant to Section 4.9.”

4. Effective January 1, 2010, or such earlier date as is specified below, Section 3.12 of the Plan is hereby amended, in its entirety, to read as follows:

“3.12. Qualified Military Service :

(a) Notwithstanding any provision of this Plan to the contrary, contributions, benefits and service credit with respect to Qualified Military Service, as such term is defined in Section 414(u)(5) of the Code, will be provided in accordance with Section 414(u) of the Code. Specifically, as required by Section 414(u)(8) of the Code, the Member will be treated as not having incurred a Break in Service because of his period of Qualified Military Service, the Member’s Qualified Military Service will be treated as Service under the Plan, and the Member will be permitted to make up any contributions he would have otherwise been eligible to make during the period of Qualified Military Service.

(b) If a Member’s death occurs on or after January 1, 2007, while performing Qualified Military Service, then, provided such Member was entitled to reemployment rights with respect to the Employer under Code Section 414(u) as of the date of his death, the Member’s Beneficiary or Beneficiaries shall be entitled to any benefits (other than benefit accruals relating to the period of Qualified Military Service) that would be provided under the Plan if the Member had resumed and then terminated his Service on account of death, in compliance with Code Section 401(a)(37) and the Treasury regulations and guidance issued by the Internal Revenue Service thereunder.

(c) If an individual is paid remuneration by an Employer after December 31, 2008 that constitutes a “differential wage payment” within the meaning of Code

Section 3401(h)(2), then (i) such individual shall be treated as an Employee of the Employer making the payment, (ii) the differential wage payment shall be treated as Compensation solely for purposes of Section 12.1(c) of the Plan.

(d) No Member or Beneficiary shall be entitled to any continued benefit accruals or employer contributions under Code Section 414(u)(9) (as enacted under section 104(b) of the Heroes Earnings Assistance and Relief Act of 2008) by reason of incurring a death or disability during a period of Qualified Military Service.”

5. Section 4.4 of the Plan is hereby amended, in its entirety, to read as follows:

“4.4 Employer Contributions : Employer Contributions may be made in the form of Matching Contributions and/or Discretionary Profit Sharing Contributions, each as defined below. Employer Contributions shall be deemed to be made on account of a Plan Year if (i) the Employer claims such amount as a deduction on its federal income tax return for such Plan Year or (ii) the Employer designates such amount in writing to the Trustee as payment on account of such Plan Year. In the case of the reinstatement of any amounts forfeited pursuant to the unclaimed benefit provisions of Section 11.10, the Employer shall also contribute, within a reasonable time after a claim is filed under Section 11.10, an amount sufficient to reinstate such amount.

(a) Matching Contributions . Each Employer shall make an Employer Contribution to the Trust Fund for a Plan Year on behalf of its Members in an amount equal to one hundred percent (100%) of such Member’s Basic Savings Contributions for the Plan Year (‘Matching Contribution’). ‘Basic Savings Contributions’ means each Member’s first six percent (6%) of Pre-Tax Contributions. After the close of each Plan Year, the applicable Employer shall make an additional Employer Contribution for each Member who is an active Member on the last day of such Plan Year in an amount equal to the difference, if any, between (1) 100% of the first 6% of the Member’s Pre-Tax Contributions (but not Catch-up Contributions) for the Plan Year and (2) the sum of the Employer Matching Contributions made for such Members for all payroll periods during the Plan Year.

(b) Discretionary Profit Sharing Contributions . For each Plan Year, the Board of Directors, in its sole and absolute discretion, may direct an Employer to make an Employer Contribution on behalf of each Member who is actively employed by such Employer during such Plan Year in an amount designated by the Board of Directors (‘Discretionary Profit Sharing Contribution’). Notwithstanding the foregoing, the Board of Directors is not required to authorize a Discretionary Profit Sharing Contribution for a Plan Year.”

6. Section 4.7 of the Plan is hereby amended, in its entirety, to read as follows:

“4.7 Delivery to Trustee . Each Employer shall transmit Contributions to the Trustee as soon as practicable, but in any event no later than the date required by law; provided, however, that all Employer Contributions shall be transmitted to the Trustee no later than the time prescribed by law for filing the federal income tax return of the Employer, including any extension which has been granted for the filing of such tax return.”

7. Section 4.9 of the Plan is hereby amended, in its entirety, to read as follows:

“4.9 Rollover Contributions : Notwithstanding any other provision of the Plan, subject to the terms and conditions set forth in this Section, the Trustee shall be authorized to accept a rollover of an Eligible Rollover Distribution, as defined in Section 8.5, on behalf of or from a person who is (or who will be entitled under Section 3.1 to become) a Member in the Plan, from an Eligible Retirement Plan, as defined in Section 8.5. Such a transferred distribution is referred to herein as a ‘Rollover Contribution.’

The acceptance of Rollover Contributions under this Section shall be subject to the following conditions:

(a) No Rollover Contribution shall be in an amount less than $500;

(b) Rollover Contributions shall be in cash only;

(c) No Rollover Contribution may be transferred to the Plan without the prior approval of the Committee. The Committee shall develop such procedures and may require such information from an Employee desiring to make such

a transfer as it deems necessary or desirable. The Committee may act in its sole discretion in determining whether to accept the transfer, and shall act in a uniform, non-discriminatory manner in this regard;

(d) Upon approval by the Committee, a Rollover Contribution shall be paid to the Trustee to be held in the Trust Fund;

(e) A separate Rollover Account shall be established and maintained for each Employee who has made a Rollover Contribution. A Rollover Account shall be invested in the Investment Funds and/or the Company Stock Fund as elected by the Employee, in the form and manner prescribed by the Committee, when the Rollover Contributions are received by the Trust Fund, and thereafter the Employee may change his investments in accordance with Section 9.4 of the Plan. The Employee’s interest in his Rollover Account shall be fully vested and non-forfeitable. If an Employee who is otherwise eligible to participate in the Plan but who has not yet begun participation under Section 3.1 of the Plan makes a Rollover Contribution to the Plan, his Rollover Account shall represent his sole interest in the Plan until he becomes a Member;

(f) The Committee shall be entitled to rely on the representation of the Employee that the Rollover Contribution is an eligible rollover distribution. If, however, it is determined that a transfer received from or on behalf of an Employee failed to qualify as an eligible rollover distribution within the meaning of Code Section 402(c)(4), then the balance in the Employee’s Rollover Account attributable to the ineligible transfer shall, along with any earnings thereon, as soon as is administratively practicable, be:

(1) segregated from all other Plan assets;

(2) treated as a non-qualified trust established by and for the benefit of the Member; and

(3) distributed to the Employee.

Such an ineligible transfer shall be deemed never to have been a part of the Plan or Trust; and

(g) The Plan shall accept a direct Rollover Contribution from the Cabot Oil & Gas Corporation Pension Plan by any Member (or Employee eligible to become a Member) who, as of the date of such Rollover Contribution, has an Account balance in the Plan, and such amount shall be maintained in a Rollover Account maintained on behalf of the Member . ”

8. Section 5.2(c) of the Plan is hereby amended, in its entirety, to read as follows:

“(c) Employer Contributions . No less frequently than once each Plan Year and more frequently as may be specified by the Committee, the Employer Contributions for such Plan Year shall be allocated among its Members during such Plan Year or partial Plan Year, as follows:

(1) Matching Contributions . Matching Contributions shall be allocated to the Member’s Matching Contribution Sub-Account in the ratio that each Member’s unwithdrawn Basic Savings Contributions (as defined in Section 4.4) for the applicable Plan Year or partial Plan Year bears to the total unwithdrawn Basic Savings Contributions of all such Members for the Plan Year or partial Plan Year.

(2) Discretionary Profit Sharing Contributions . Discretionary Profit Sharing Contributions received in the Trust Fund for a Plan Year, if any, shall be allocated on each Allocation Date to the Discretionary Profit Sharing Contribution Sub-Account of each eligible Member in the ratio that the Member’s Considered Compensation for the applicable Allocation Period bears to the aggregate Considered Compensation of all Members for such Allocation Period. For purposes of this Section 5.2(c)(2), (i) ‘Allocation Date’ means the date on which an allocation of Discretionary Profit Sharing Contributions; (ii) ‘Allocation Period’ shall mean the period commencing on the date next following the previous Allocation Date and ending on the current Allocation Date; and (iii) ‘Considered Compensation’ shall mean a Member’s Compensation for the applicable Allocation Period; For the Plan Year ending December 31, 2010, a Member’s Considered Compensation shall not

include Compensation attributable to services performed prior to October 1, 2010 and no Allocation Date shall be deemed to have occurred prior to October 1, 2010.”

9. Section 6.5 of the Plan is hereby amended, in its entirety, to read as follows:

“6.5 Loans to Members : Except as provided below, the availability of loans are limited to Members who are Employees (hereinafter “Borrowers”), who may make application to the Committee to borrow from the Accounts maintained by or for the Borrower in the Trust Fund other than the Discretionary Profit Sharing Sub-Account and the portion of the Rollover Account attributable to rollovers from the Cabot Oil & Gas Corporation Pension Plan (the “Loan Eligible Account”). Additionally, in order for the exemption set forth in 29 C.F.R. 2550.408b-1 to apply to the Plan, a Borrower may also include, but only to the extent not resulting in discrimination prohibited by Section 401(a)(4) of the Code, any other Member or Beneficiary who is a “party in interest” with respect to the Plan within the meaning of ERISA Section 3(14). It is within the sole discretion of the Committee whether or not to permit such a loan. Loans shall be granted in a uniform and non-discriminatory manner on terms and conditions determined by the Committee which shall not result in more favorable treatment of highly compensated employees and shall be set forth in written procedures promulgated by the Committee in accordance with applicable governmental regulations. All such loans shall also be subject to the following terms and conditions:

(a) The amount of the loan, when added to the amount of any outstanding loan or loans to the Borrower from any other plan of the Employer or an Affiliate which is qualified under Section 401(a) of the Code, shall not exceed the lesser of (i) $50,000, reduced by the excess, if any, of the highest outstanding balance of loans from all such plans during the one-year period ending on the day before the date on which such loan was made over the outstanding balance of loans from the Plan on the date on which such loan was made or (ii) fifty percent (50%) of the present value of the Borrower’s vested Loan Eligible Account balance under the Plan. In no event shall a loan of less than $1,000 be made to a Borrower. A Borrower may not have more than one (1) loan outstanding at a time under this Plan, and a Borrower

will be limited to a maximum of one (1) loan per year from this Plan.

(b) The loan shall be for a term not to exceed five (5) years, and shall be evidenced by a note signed by the Borrower. The loan shall be payable in periodic installments and shall bear interest at a reasonable rate which shall be determined by the Committee on a uniform and consistent basis and set forth in the procedures in accordance with applicable governmental regulations. Payments by a Borrower who is an Employee will be made by means of payroll deduction from the Borrower’s compensation. If a Borrower is not receiving compensation from the Employer, the loan repayment shall be made in accordance with the terms and procedures established by the Committee. A Borrower may repay an outstanding loan in full at any time.

(c) In the event an installment payment is not paid within seven (7) days following the monthly due date, the Committee shall give written notice to the Borrower sent to his last known address. If such installment payment is not made within thirty (30) days thereafter, the Committee shall proceed with foreclosure in order to collect the full remaining loan balance or shall make such other arrangements with the Borrower as the Committee deems appropriate. Foreclosure need not be effected until occurrence of a distributable event under the terms of the Plan and no rights against the Borrower or the security shall be deemed waived by the Plan as a result of such delay.

(d) The unpaid balance of the loan, together with interest thereon, shall become due and payable upon the date of distribution of any portion of the Loan Eligible Account and the Trustee shall first satisfy the indebtedness from the amount payable to the Borrower or to the Borrower’s Beneficiary before making any payments to the Borrower or to the Borrower’s Beneficiary.

(e) Any loan to a Borrower under the Plan shall be adequately secured. Such security may include a pledge of a portion of the Borrower’s right, title and interest in the Trust Fund which shall not exceed fifty percent (50%) of the present value of the Borrower’s vested Loan Eligible Account balance under the Plan as determined immediately after the loan is extended. Such pledge shall be evidenced by the execution of a promissory note by the Borrower

which shall grant the security interest and provide that, in the event of any default by the Borrower on a loan repayment, the Committee shall be authorized to take any and all appropriate lawful actions necessary to enforce collection of the unpaid loan.

(f) A request by a Borrower for a loan shall be made in writing to the Committee and shall specify the amount of the loan. If a Borrower’s request for a loan is approved by the Committee, the Committee shall furnish the Trustee with written instructions directing the Trustee to make the loan in a lump-sum payment of cash to the Borrower. The cash for such payment shall be obtained by redeeming proportionately as of the date of payment the Investment Fund or Investment Funds, or portions thereof, that are credited to the particular Loan Eligible Account of such Borrower.

(g) A loan to a Borrower shall be considered an investment of the separate Loan Eligible Account(s) of the Borrower from which the loan is made. All loan repayments shall be credited pro rata to such separate Loan Eligible Account(s) and reinvested exclusively in shares of one or more of the Investment Funds in accordance with the Borrower’s most recent investment direction made in accordance with Section 9.3.”

10. The fourth paragraph of Section 8.1 of the Plan is hereby amended to read as follows:

“The amount which a Member, former Member or Beneficiary is entitled to receive at any time and from time to time shall be paid in cash as a lump sum, except amounts payable to or on behalf of Members who have shares of Cabot Oil & Gas Corporation stock in their Profit-Sharing Plan Account or their ESOP Account may have their stock balance paid in cash or as stock certificates adjusted to reflect commission fees.”

11. Section 9.2 of the Plan is hereby amended, in its entirety, to read as follows:

“9.2 Investment Funds : The Trustee shall divide the Trust Fund into the Cabot Oil & Gas Corporation Stock Fund and such additional Investment Funds which shall be selected and reviewed from time to time by the Committee. Effective September 30, 2010, the Cabot

Corporation Common Stock Fund shall no longer be offered pursuant to the Plan.

Contributions shall be paid into the Investment Funds pursuant to the directions of the Members given in accordance with the provisions of Sections 9.3 and 9.4 as certified to the Trustee by the Committee. Except as otherwise provided herein, interest, dividends and other income and all profits and gains produced by each such Investment Fund shall be paid into such Investment Fund, and such interest, dividends and other income or profits and gains, without distinction between principal and income, may be invested and reinvested but only in the property hereinabove specified for the particular Investment Fund.”

IN WITNESS WHEREOF, the Company, acting by and through its duly authorized officer, has caused this Amendment to be executed as of the 10th day of September 2010, to become effective as of the dates set forth above.


CABOT OIL & GAS CORPORATION

By:		/s/ Abraham Garza

Title:		Vice President, Human Resources

Exhibit 21.1

SUBSIDIARIES OF CABOT OIL & GAS CORPORATION

Big Sandy Gas Company

Cabot Oil & Gas Marketing Corporation *

Cody Energy, LLC

Cody Oil & Gas, Inc.

Cranberry Pipeline Corporation *

Cabot Petroleum Canada Corporation

Cabot Oil & Gas Holdings Company

COG Finance Corporation

Gas Search Drilling Services Corporation

Cody Texas, L.P.

Susquehanna Real Estate I Corporation

*	Denotes significant subsidiary.

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (File Nos. 333-68350, 333-83819 and 333-151725) and Form S-8 (File Nos. 333-37632, 33-53723, 33-35476, 333-92264, 333-123166 and 333-135365) of Cabot Oil & Gas Corporation of our report dated February 28, 2011 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopersLLP

Houston, Texas

February 28, 2011

Exhibit 23.2

February 16, 2011

Cabot Oil & Gas Corporation

Three Memorial City Plaza

840 Gessner

Suite 1400

Houston, TX 77024

Re:

Securities and Exchange Commission

Form 10-K of Cabot Oil & Gas Corporation

Gentlemen:

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-68350, 333-83819 and 333-151725) and Form S-8 (File Nos. 333-37632, 33-53723, 33-35476, 333-92264, 333-123166 and 333-135365) of Cabot Oil & Gas Corporation of our report dated February 1, 2011, regarding the Cabot Oil & Gas Corporation Proved Reserves and Future Net Revenues as of December 31, 2010, and of references to our firm which report and references are to be included in Form 10-K for the year ended December 31, 2010 to be filed by Cabot Oil & Gas Corporation with the Securities and Exchange Commission.

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

Yours very truly,

MILLER AND LENTS, LTD.

Texas Registered Engineering Firm No. F-1442

/s/ Carl D. Richard

Carl D. Richard, P.E.

Senior Vice President

Exhibit 31.1

I, Dan O. Dinges, certify that:

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

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

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

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

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

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

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

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

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

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

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

Date: February 28, 2011

/s/ Dan O. Dinges

Dan O. Dinges

Chairman, President and

Chief Executive Officer

Exhibit 31.2

I, Scott C. Schroeder, certify that:

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

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

Date: February 28, 2011

/s/ Scott C. Schroeder

Scott C. Schroeder

Vice President and Chief Financial Officer

Exhibit 32.1

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

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

(1) the Company’s Annual Report on Form 10-K for the year ended December 31, 2010 (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, 2011						/s/ Dan O. Dinges
						Dan O. Dinges
						Chief Executive Officer

						/s/ Scott C. Schroeder
						Scott C. Schroeder
						Chief Financial Officer

Exhibit 99.1

LOGO

February 1, 2011

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, 2010
		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, 2010. The audit report was prepared for the use of Cabot in its annual financial and reserves reporting and was completed on January 31, 2011. Cabot’s estimates, shown below, are in accordance with the definitions contained in Securities and Exchange Commission (SEC) Regulation S-X, Rule 4-10(a) as shown in the Appendix.

Reserves and Future Net Revenues as of December 31, 2010

Reserves Category

Net Reserves

Future Net Revenues

Liquids,

MBbls.

Gas,

MMcf

Undiscounted,

Discounted at

10% Per Year,

Proved Developed

7,129

1,681,451

5,596,815

2,628,906

Proved Undeveloped

2,361

962,707

2,502,604

627,435

Total Proved

9,490

2,644,158

8,099,419

3,256,341

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.

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Cabot Oil & Gas Corporation		February 1, 2011
		Page 2

Cabot’s reserves estimates were based on decline curve extrapolations, material balance calculations, volumetric calculations, analogies, or combinations of these methods for each well, reservoir, or field. Reserves estimates from volumetric calculations and from analogies are often less certain than reserves estimates based on well performance obtained over a period during which a substantial portion of the reserves were produced.

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

Cabot represents that the future net revenues reported herein were computed based on prices for oil and gas, utilizing the 12-month averages of the first-day-of-the-month prices, and are in accordance with SEC guidelines. Cabot used benchmark prices of $79.43 per barrel based on the West Texas Intermediate Spot Price at Cushing, Oklahoma and $4.376 per MMBtu based on the Henry Hub Spot Price for its reserves estimates. The present value of future net revenues was computed by discounting the future net revenues at 10 per cent per year. Estimates of future net revenues and the present value of future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

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

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

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

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Cabot Oil & Gas Corporation		February 1, 2011
		Page 3

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments and are subject to the inherent uncertainties associated with interpretation of geological, geophysical, and engineering information. These uncertainties include, but are not limited to, (1) the utilization of analogous or indirect data and (2) the application of professional judgments. Government policies and market conditions different from those employed in this study may cause (1) the total quantity of oil, natural gas liquids, or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. At this time, MLL is not aware of any regulations that would affect Cabot’s ability to recover the estimated reserves.

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

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


				Very truly yours,

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

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

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

JAC/CDR/psh