10-K

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, 2005

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 incorporation or organization)	(I.R.S. Employer Identification Number)

1200 Enclave Parkway, Houston, Texas 77077

(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
Rights to Purchase Preferred Stock	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 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, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨

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

The aggregate market value of Common Stock, par value $.10 per share (“Common Stock”), held by non-affiliates (based upon the closing sales price on the New York Stock Exchange on June 30, 2005), as of the last business day of registrant’s most recently completed second fiscal quarter was approximately $1.7 billion.

As of January 31, 2006, there were 48,610,408 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held May 4, 2006 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

		PAGE
PART I
ITEM 1	Business	3
ITEM 1A	Risk Factors	18
ITEM 1B	Unresolved Staff Comments	23
ITEM 2	Properties	23
ITEM 3	Legal Proceedings	24
ITEM 4	Submission of Matters to a Vote of Security Holders	25
	Executive Officers of the Registrant	26
PART II
ITEM 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
ITEM 6	Selected Financial Data	28
ITEM 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
ITEM 7A	Quantitative and Qualitative Disclosures about Market Risk	50
ITEM 8	Financial Statements and Supplementary Data	53
ITEM 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	93
ITEM 9A	Controls and Procedures	94
ITEM 9B	Other Information	94
PART III
ITEM 10	Directors and Executive Officers of the Registrant	94
ITEM 11	Executive Compensation	95
ITEM 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	95
ITEM 13	Certain Relationships and Related Transactions	95
ITEM 14	Principal Accounting Fees and Services	95
PART IV
ITEM 15	Exhibits and Financial Statement Schedules	95

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. 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, and other factors detailed in this document and in our other Securities and Exchange Commission filings. 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.

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PART I

ITEM 1. BUSINESS

OVERVIEW

Cabot Oil & Gas is an independent oil and gas company engaged in the exploration, development, acquisition and exploitation of oil and gas properties located in North America. The five principal areas of operation are Appalachian Basin, Rocky Mountains, Anadarko Basin, onshore and offshore the Texas and Louisiana Gulf Coast, and the gas basin of Western Canada. Operationally, we have four regional offices located in Houston, Texas; Charleston, West Virginia; Denver, Colorado; and Calgary, Alberta.

Net income for 2005 of $148.4 million, or $3.04 per share, exceeded the prior year’s net income of $88.4 million or $1.81 per share, by $60.0 million, or $1.23 per share. The per share data for 2004 has been adjusted for the 3-for-2 split of our stock that occurred in March 2005. The year-over-year net income increase was achieved due to higher natural gas and crude oil production revenues, primarily as a result of higher commodity prices, partially offset by higher operating expenses and taxes. Operating Revenues increased by $152.4 million or 29% due to strong commodity prices. Natural gas production revenues increased by $119.5 million over the prior year. Crude oil and condensate revenues and brokered natural gas revenues also increased by $14.2 million and $22.3 million, respectively. Partially offsetting these increased revenues, operating expenses increased by $54.5 million between 2005 and 2004. This increase was principally due to increased exploration costs, brokered natural gas costs and taxes other than income. Net income in 2005 was also reduced by an increase in income tax expense of $37.6 million. At December 31, 2005, our debt-to-total-capital ratio was 36%, down slightly from 37% at the end of 2004.

Natural gas production increased to 73.9 Bcf in 2005 from 72.8 Bcf in 2004. This growth resulted from our 2004 and 2005 drilling programs, which focused on natural gas projects, especially in the East. On an equivalent basis, our production level in 2005 was down slightly from 2004. We produced 84.4 Bcfe, or 231.1 Mmcfe per day, in 2005, as compared to 84.8 Bcfe, or 232.3 Mmcfe per day, in 2004. The growth in natural gas production was offset by the natural decline in oil production in south Louisiana, as well as the impact of the hurricanes which included the shutting in and deferring of production at the Breton Sound offshore lease, one of our largest areas of offshore oil production.

In 2005, energy commodity prices remained strong throughout the year. Our 2005 realized natural gas price was $6.74 per Mcf, compared to a 2004 price of $5.20. Our realized crude oil price was $44.19 per Bbl, compared to a 2004 price of $31.55. These realized prices include the realized impact of derivative instruments. This strong price environment allowed us to pursue our largest organic capital program ever while still maintaining our financial flexibility. In the current year, this flexibility allowed us the ability to acquire additional interests in two fields in the Gulf Coast. We believe that as a result of our strong capital program and financial flexibility, we should be able to continue to take advantage of additional attractive acquisition opportunities that may arise.

A portion of our production was covered by oil and gas hedge instruments throughout 2005 to cover production in 2005 and 2006. At December 31, 2005, 33% and 26% of our natural gas and crude oil anticipated production, respectively, are hedged for 2006 through the use of derivatives that qualify for hedge accounting. As of December 31, 2005, no derivatives are in place for 2007. Our decision to hedge 2006 production fits with our risk management strategy and allows us to lock in the benefit of high commodity prices on a portion of our anticipated production. Our average hedged prices on natural gas and crude oil for 2006 anticipated production are expected to be higher than comparable prices realized in 2005.

For the year ended December 31, 2005, we drilled 316 gross wells with a success rate of 95% compared to 256 gross wells with a success rate of 95% for the prior year. In 2006, we plan to drill approximately 391 gross wells.

Our proved reserves totaled approximately 1,331 Bcfe at December 31, 2005, of which 95% was natural gas. This reserve level was up by 11% from 1,202 Bcfe at December 31, 2004 on the strength of results from our drilling program and the increase in our capital spending.

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Our 2005 capital and exploration spending was $425.6 million, including $73.1 million, primarily in the Gulf Coast, to acquire proved producing properties, compared to $259.5 million of total capital and exploration spending in 2004. We remain focused on our strategies of balancing our capital investments between acceptable risk and strongest economics, along with balancing longer life investments with impact exploration opportunities. In the past, we have used a portion of the cash flow from our long-lived East and Mid-Continent natural gas reserves to fund our exploration and development efforts in the Gulf Coast and Rocky Mountains areas. We have continued that practice, and the allocation of capital among regions in 2005 was similar in percentage to the allocation in 2004, with the Gulf Coast region being allocated an additional 12% in capital over the previous year. In 2006, we plan to spend approximately $396 million which includes a layer of investment for new projects or property acquisitions that may arise during the year.

In March 2005, we completed a 3-for-2 split of our common stock in the form of a stock distribution. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of our common stock.

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

The following table presents certain reserve, production and well information as of December 31, 2005.

			West
	East		Rocky Mountains		Mid- Continent		Total		Gulf Coast		Canada		Total
Proved Reserves at Year End (Bcfe)
Developed	448.4		189.5		169.3		358.8		172.9		19.6		999.7
Undeveloped	189.0		51.7		21.8		73.5		68.0		0.7		331.2
Total	637.4		241.2		191.1		432.3		240.9		20.3		1,330.9
Average Daily Production (Mmcfe per day)	59.2		37.3		29.1		66.4		102.1		3.4		231.1
Reserve Life Index (in years) (1)	29.5		17.7		18.0		17.8		6.5		16.2		15.8
Gross Wells	2,745		576		680		1,256		788		20		4,809
Net Wells (2)	2,550.2		252.4		471.8		724.2		515.7		3.9		3,794.0
Percent Wells Operated (Gross)	96.8	%	51.2	%	76.9	%	65.1	%	73.9	%	40.0	%	84.5	%

⁽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.

EAST REGION

Our East activities are concentrated primarily in West Virginia. In this region, our assets include a large acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity. Capital and exploration expenditures were $99.0 million, or 23% of our total 2005 capital spending, and $75.2 million, or 29% of our total 2004 capital spending. For 2006, we have budgeted $116.1 million for capital and exploration expenditures in the region.

At December 31, 2005, we had 2,745 wells (2,550.2 net), of which 2,657 wells are operated by us. There are multiple producing intervals that include the Big Lime, Weir, Berea and Devonian Shale formations at depths primarily ranging from 1,000 to 9,500 feet. Average net daily production in 2005 was 59.2 Mmcfe. While natural gas production volumes from East reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of East reserves is relatively long. At December 31, 2005, we had 637.4 Bcfe of proved reserves (substantially all natural gas) in the East region, constituting 48% of our total proved reserves. This region is managed from our office in Charleston, West Virginia.

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In 2005, we drilled 185 wells (179.8 net) in the East region, of which 182 wells (176.8 net) were development and extension wells. In 2006, we plan to drill approximately 239 wells.

In 2005, we produced and marketed approximately 70 barrels of crude oil/condensate per day in the East region at market responsive prices.

Ancillary to our exploration, development and production operations, we operate a number of gas gathering and transmission pipeline systems with interconnects to three interstate transmission systems, seven local distribution companies and numerous end users as of the end of 2005. The majority of our pipeline infrastructure in West Virginia is regulated by the Federal Energy Regulatory Commission (FERC). 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. Our natural gas gathering and transmission pipeline systems 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 East region. The pipeline systems and storage fields are fully integrated with our operations.

The principal markets for our East region natural gas are in the northeast 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 65% of our natural gas sales volume in the East region is sold at index-based prices under contracts with a term of one year or greater. In addition, spot market sales are made under month-to-month contracts, while industrial and utility sales generally are made under year-to-year contracts. Approximately 2% of East production is sold on fixed price contracts that typically renew annually.

WEST REGION

Our activities in the West region are managed by a regional office in Denver, Colorado. At December 31, 2005, we had 432.3 Bcfe of proved reserves (96% natural gas) in the West region, constituting 32% of our total proved reserves.

Rocky Mountains

Activities in the Rocky Mountains are concentrated in the Green River, Washakie and Big Horn Basins in Wyoming and Paradox Basin in Colorado. At December 31, 2005, we had 241.2 Bcfe of proved reserves (95% natural gas) in the Rocky Mountains area, or 18% of our total proved reserves. Capital and exploration expenditures in the Rocky Mountains were $45.4 million for 2005, or 11% of our total capital and exploration expenditures, and $41.5 million for 2004. For 2006, we have budgeted $57.8 million for capital and exploration expenditures in the area.

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We had 576 wells (252.4 net) in the Rocky Mountains area as of December 31, 2005, of which 295 wells are operated by us. Principal producing intervals in the Rocky Mountains area are in the Almond, Frontier, Dakota and Honaker Trail formations at depths ranging from 5,500 to 15,000 feet. Average net daily production in the Rocky Mountains during 2005 was 37.3 Mmcfe.

In 2005, we drilled 49 wells (16.1 net) in the Rocky Mountains, of which 45 wells (13.3 net) were development wells. In 2006, we plan to drill 42 wells.

Mid-Continent

Our Mid-Continent activities are concentrated in the Anadarko Basin in southwest Kansas, Oklahoma and the panhandle of Texas. Capital and exploration expenditures were $23.7 million for 2005, or 6% of our total 2005 capital and exploration expenditures, and $12.1 million for 2004. For 2006, we have budgeted $33.1 million for capital and exploration expenditures in the area.

As of December 31, 2005, we had 680 wells (471.8 net) in the Mid-Continent area, of which 523 wells are operated by us. Principal producing intervals in the Mid-Continent are in the Chase, Morrow, Red Fork and Chester formations at depths ranging from 2,200 to 10,000 feet. Average net daily production in 2005 was 29.1 Mmcfe. At December 31, 2005, we had 191.1 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, or 14% of our total proved reserves.

In 2005, we drilled 34 wells (21.5 net) in the Mid-Continent, all of which were development and extension wells. In 2006, we plan to drill 42 wells.

Our principal markets for West region natural gas are in the northwest and midwest United States. We sell natural gas to power generators, natural gas processors, local distribution companies, industrial customers and marketing companies. Currently, approximately 75% of our natural gas production in the West region is sold primarily under contracts with a term of one to three years at index-based prices. Another 23% of the natural gas production is sold under short-term arrangements at index-based prices and the remaining 2% is sold under certain fixed-price contracts. The West region properties are connected to the majority of the midwest and northwest interstate and intrastate pipelines, affording us access to multiple markets.

In 2005, we produced and marketed approximately 450 barrels of crude oil/condensate per day in the West region at market responsive prices.

GULF COAST REGION

Our exploration, development and production activities in the Gulf Coast region are primarily concentrated in north and south Louisiana, south Texas and, to a lesser extent, the Gulf of Mexico. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley, Hosston, Miocene and Frio age formations in Louisiana and the Frio, Vicksburg and Wilcox formations in Texas at depths ranging from 3,000 to 25,000 feet. Capital and exploration expenditures were $233.5 million for 2005, or 55% of our total capital and exploration expenditures, and $112.6 million for 2004. During 2005, we spent $72.1 million on proved property acquisitions. For 2006, we have budgeted $154.4 million of our total budget for capital and exploration expenditures in the region. Our 2006 Gulf Coast drilling program will emphasize activity in our focus areas of east Texas, north Louisiana and south Texas.

In 2005, we drilled 39 wells (26.2 net) in the Gulf Coast region, of which 23 wells (17.4 net) were development wells. In 2006, we plan to drill 55 wells. We had 788 wells (515.7 net) in the Gulf Coast region as of December 31, 2005, of which 582 wells are operated by us. Average daily production in 2005 was 102.1 Mmcfe, compared to 115.3 Mmcfe in 2004. The decline is the result of lower production from our properties in south Louisiana, offset partially by increased production from the coastal Texas area. At December 31, 2005, we had 240.9 Bcfe of proved reserves (80% natural gas) in the Gulf Coast region, which represented 18% of our total proved reserves.

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Our principal markets for Gulf Coast region natural gas are in the industrialized Gulf Coast area and the northeast United States. We sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Currently, approximately 50% of our natural gas sales volumes in the Gulf Coast region are sold at index-based prices under contracts with terms of one to three years. The remaining 50% of our sales volumes are sold at index-based prices under short-term agreements. The Gulf Coast properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.

In 2005, we produced and marketed approximately 4,100 barrels of crude oil/condensate per day in the Gulf Coast region at market responsive prices.

CANADA REGION

Our activities in the Canada region are managed by a regional office in Calgary, Alberta. Our Canadian exploration, development and producing activities are concentrated in the Provinces of Alberta and British Columbia. At December 31, 2005, we had 20.3 Bcfe of proved reserves (97% natural gas) in the Canada region, constituting 2% of our total proved reserves.

Capital and exploration expenditures in Canada were $22.9 million for 2005, or 5% of our total capital and exploration expenditures, and $16.2 million for 2004. For 2006, we have budgeted $30.7 million for capital and exploration expenditures in the area.

We had 20 wells (3.9 net) in the Canada region as of December 31, 2005, of which 8 wells are operated by us. Principal producing intervals in the Canada region are in the Falher, Bluesky, Cadomin and the Swan Hills formations at depths ranging from 9,500 to 16,000 feet. Average net daily production in Canada during 2005 was 3.4 Mmcfe.

In 2005, we drilled 9 wells (3.5 net) in Canada, of which 5 wells (1.7 net) were development and extension wells. In 2006, we plan to drill 13 wells.

In 2005, we produced and marketed approximately 50 barrels of crude oil/condensate per day in the Canada region at market responsive prices.

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 2005 we primarily employed natural gas and crude oil price swap and collar agreements to attempt to manage price risk more effectively. 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. 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 is below the floor.

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.

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RESERVES

Current Reserves

The following table presents our estimated proved reserves at December 31, 2005.

	Natural Gas (Mmcf)			Liquids(1) (Mbbl)			Total(2) (Mmcfe)
	Developed	Undeveloped	Total	Developed	Undeveloped	Total	Developed	Undeveloped	Total
East	445,964	188,976	634,940	403	—	403	448,379	188,976	637,355
Rocky Mountains	179,730	49,629	229,359	1,631	344	1,975	189,514	51,696	241,210
Mid-Continent	163,815	21,563	185,378	913	41	954	169,295	21,811	191,106
Gulf Coast	136,417	56,344	192,761	6,077	1,943	8,020	172,882	67,999	240,881
Canada	18,971	687	19,658	103	8	111	19,591	731	20,322
Total	944,897	317,199	1,262,096	9,127	2,336	11,463	999,661	331,213	1,330,874

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

⁽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.

The proved reserve estimates presented here were prepared by our petroleum engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum engineers. Miller and Lents concluded the following: In their judgment 1) we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues, 2) we used appropriate engineering, geologic and evaluation principles in making our estimates and projections and 3) our total proved reserves are reasonable. For additional information regarding estimates of proved reserves, the review 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 review letter by Miller and Lents, Ltd. has been filed as an exhibit to this Form 10-K. Our estimates of proved reserves in the table above are consistent with those filed by us with other federal agencies. During 2005, we filed estimates of our oil and gas reserves for the year 2004 with the Department of Energy. These estimates differ by 5 percent or less from the reserve data presented. Our reserves are sensitive to natural gas and crude oil sales prices and their effect on economic producing rates. Our reserves are based on oil and gas index prices in effect on the last day of December 2005. If we had considered the impact of our hedging activities in our proved reserves, there would not have been any significant effect.

For additional information about the risks inherent in our estimates of proved reserves, see “Risk Factors—Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated” in Item 1A.

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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, 2002	1,060,959		18,393		1,171,316
Revision of Prior Estimates	(6,122	)	307		(4,278	)
Extensions, Discoveries and Other Additions	105,497		1,723		115,835
Production	(71,906	)	(2,846	)	(88,976	)
Purchases of Reserves in Place	1,590		—		1,591
Sales of Reserves in Place	(20,534	)	(5,474	)	(53,380	)
December 31, 2003	1,069,484		12,103		1,142,108
Revision of Prior Estimates	(7,850	)	185		(6,739	)
Extensions, Discoveries and Other Additions	140,986		1,074		147,426
Production	(72,833	)	(2,002	)	(84,847	)
Purchases of Reserves in Place	5,384		24		5,525
Sales of Reserves in Place	(1,090	)	—		(1,090	)
December 31, 2004	1,134,081		11,384		1,202,383
Revision of Prior Estimates	(1,543	)	1,073		4,892
Extensions, Discoveries and Other Additions	185,884		334		187,891
Production	(73,879	)	(1,747	)	(84,361	)
Purchases of Reserves in Place	17,567		419		20,083
Sales of Reserves in Place	(14	)	—		(14	)
December 31, 2005	1,262,096		11,463		1,330,874
Proved Developed Reserves
December 31, 2002	819,412		13,267		899,016
December 31, 2003	812,280		9,405		868,712
December 31, 2004	857,834		8,652		909,747
December 31, 2005	944,897		9,127		999,661

⁽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.

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Volumes and Prices: Production Costs

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,
	2005		2004		2003
Net Wellhead Sales Volume
Natural Gas (Bcf)
Gulf Coast		28.1		31.3		30.0
West		23.2		21.9		23.8
East		21.4		19.4		18.6
Canada		1.2		0.2		—
Crude/Condensate/Ngl (Mbbl)
Gulf Coast		1,530		1,809		2,625
West		172		163		193
East		27		27		27
Canada		18		3		—
Produced Natural Gas Sales Price ($/Mcf) (1)
Gulf Coast	$	6.38	$	5.27	$	4.78
West		6.00		4.75		3.67
East		8.02		5.60		5.15
Canada		6.79		4.69		—
Weighted Average		6.74		5.20		4.51
Crude/Condensate Sales Price ($/Bbl) (1)	$	44.19	$	31.55	$	29.55
Production Costs ($/Mcfe) (2)	$	1.23	$	0.99	$	0.87

⁽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).

⁽²⁾ Production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), the costs of administration of production offices, insurance and property and severance taxes, but is exclusive of depreciation and depletion applicable to capitalized lease acquisition, exploration and development expenditures.

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	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Leasehold Acreage by State
Arkansas	1,981	425	0	0	1,981	425
Colorado	16,268	14,053	208,597	131,490	224,865	145,543
Kansas	29,067	27,745	0	0	29,067	27,745
Louisiana	67,324	43,186	182,211	151,840	249,535	195,026
Montana	397	210	14,102	10,835	14,499	11,045
New York	2,956	1,105	10,642	5,683	13,598	6,788
Ohio	6,247	2,384	1,625	436	7,872	2,820
Oklahoma	173,208	120,257	15,407	11,110	188,615	131,367
Pennsylvania	112,522	63,986	108	43	112,630	64,029
Texas	109,837	75,737	83,540	67,690	193,377	143,427
Utah	1,740	529	180,257	96,425	181,997	96,954
Virginia	22,298	20,201	2,642	1,558	24,940	21,759
West Virginia	582,411	549,728	206,725	192,171	789,136	741,899
Wyoming	141,317	73,074	297,342	171,176	438,659	244,250
Total	1,267,573	992,620	1,203,198	840,457	2,470,771	1,833,077
Mineral Fee Acreage by State
Colorado	0	0	2,899	271	2,899	271
Kansas	160	128	0	0	160	128
Louisiana	628	276	0	0	628	276
Montana	0	0	589	75	589	75
New York	0	0	6,545	1,353	6,545	1,353
Oklahoma	16,580	13,979	730	179	17,310	14,158
Pennsylvania	524	524	1,573	502	2,097	1,026
Texas	27	27	754	327	781	354
Virginia	17,817	17,817	100	34	17,917	17,851
West Virginia	97,455	79,488	51,603	49,671	149,058	129,159
Total	133,191	112,239	64,793	52,412	197,984	164,651
Aggregate Total	1,400,764	1,104,859	1,267,991	892,869	2,668,755	1,997,728
	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Canada Leasehold Acreage by Province
Alberta	5,760	1,910	38,472	9,128	44,232	11,038
British Columbia	700	280	11,988	4,731	12,688	5,011
Sasketchewan	0	0	9,903	9,903	9,903	9,903
Total	6,460	2,190	60,363	23,762	66,823	25,952

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Total Net Acreage by Region of Operation

	Developed	Undeveloped	Total
East	735,233	251,451	986,684
West	277,246	422,015	699,261
Gulf Coast	92,380	219,403	311,783
Canada	2,190	23,762	25,952
Total	1,107,049	916,631	2,023,680

Total Net Undeveloped Acreage Expiration by Region of Operation

The following table presents our net undeveloped acreage expiring over the next three years by operating region as of December 31, 2005. The figures below assume no future successful development or renewal of undeveloped acreage.

	2006	2007	2008
East	12,407	55,451	43,732
West	69,180	67,322	152,744
Gulf Coast	13,168	65,559	89,485
Canada	3,118	14,155	224
Total	97,873	202,487	286,185

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Well Summary

The following table presents our ownership at December 31, 2005, in productive natural gas and oil wells in the East region (consisting of various fields located in West Virginia, Virginia and Ohio), in the West region (consisting of various fields located in Oklahoma, Kansas, Colorado and Wyoming), in the Gulf Coast region (consisting primarily of various fields located in Louisiana and Texas) and in the Canada region (consisting of various fields located in the Provinces of Alberta and British Columbia). 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
East	2,720	2,538.2	25	12.0	2,745	2,550.2
West	1,201	690.5	55	33.7	1,256	724.2
Gulf Coast	622	375.0	166	140.7	788	515.7
Canada	20	3.9	0	0.0	20	3.9
Total	4,563	3,607.6	246	186.4	4,809	3,794.0

⁽¹⁾ Total does not include service wells of 73 (65.3 net).

Drilling Activity

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

	Year Ended December 31, 2005
	East		West		Gulf Coast		Canada		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Development Wells
Successful	182	176.8	75	32.6	19	13.7	5	1.6	281	224.7
Dry	0	0.0	3	1.8	0	0.0	0	0.0	3	1.8
Extension Wells
Successful	0	0.0	1	0.4	3	2.7	0	0.0	4	3.1
Dry	0	0.0	0	0.0	1	1.0	0	0.0	1	1.0
Exploratory Wells
Successful	3	3.0	1	0.7	10	6.0	1	0.7	15	10.4
Dry	0	0.0	3	2.1	6	2.8	3	1.2	12	6.1
Total	185	179.8	83	37.6	39	26.2	9	3.5	316	247.1
Wells Acquired	0	0.0	0	0.0	16	2.8	0	0.0	16	2.8
Wells in Progress at End of Year	3	3.0	3	2.0	5	3.0	3	1.1	14	9.1

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Competition

Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery records, affect competition. We believe that our extensive acreage position, existing natural gas gathering and pipeline systems and storage fields enhance our competitive position over other producers in the East region who do not have similar systems or facilities in place. We also actively compete against other companies with substantially larger financial and other resources, particularly in the West and Gulf Coast regions and Canada.

OTHER BUSINESS MATTERS

Major Customer

In each of 2005, 2004 and 2003, approximately 11% of our total sales were made to one customer.

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 provisions of the Energy Policy Act of 2005, the NGA has been amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas, and the FERC has been directed to establish new regulations that are intended to increase natural gas pricing transparency through, among other things, expanded dissemination of information about the availability and prices of gas sold. The 2005 Act also significantly increases the penalties for violations of the NGA.

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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 developed rules governing the relationship of the pipelines with their marketing affiliates, and 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, 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 pipeline facilities within the next ten years, and at least every seven years thereafter. In addition, beginning in early 2006, the DOT’s Pipeline and Hazardous Materials Safety Administration commenced a rulemaking proceeding to develop rules that would better distinguish onshore gathering lines from production facilities and transmission lines, and to develop safety requirements better tailored to gathering line risks. We are not able to predict with certainty the final outcome of this rulemaking proposal.

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. The second of these required reviews commenced in July 2005, where the FERC proposed to continue use of the indexing methodology for a further five year period.

Another FERC proceeding that may impact our transportation costs relates to an ongoing proceeding to determine whether and to what extent pipelines should be permitted to include in their transportation rates an allowance for

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income taxes attributable to non-corporate partnership interests. Following a court remand, the FERC has established a policy that a pipeline structured as a master limited partnership or similar non-corporate entity is entitled to 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 are not able to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or the final outcome of the application of the FERC’s new 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 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.

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.

Outer Continental Shelf Lands Act. The federal Outer Continental Shelf Lands Act (OCSLA) and regulations promulgated pursuant thereto impose a variety of regulations relating to safety and environmental protection applicable to lessees, permit holders and other parties operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to the Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or citizen prosecution. We believe that we substantially comply with the OCSLA and its regulations.

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 solid 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 more strict 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

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and operator of a site and any party that disposed of or arranged for the 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 generated and will continue to 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 wastes have been disposed.

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 (FWPCA or Clean Water Act) and resulting regulations, which are 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 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 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 that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.

Employees

As of December 31, 2005, Cabot Oil & Gas had 354 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 report 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. 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 filed by the Company.

Corporate Governance Matters

The Company’s Corporate Governance Guidelines, 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 “Corporate Governance” section of “Investor Relations” and a copy will be provided, without charge, to any shareholder upon request. Requests can also be made in writing to Investor Relations at our corporate headquarters at 1200 Enclave Parkway, Houston, Texas, 77077. We have filed the required certifications of our chief executive officer and our chief financial officer under Section 302 of the Sarbanes-Oxley Act of 2002 as exhibits 31.1 and 31.2 to this Form 10-K. In 2005, we submitted to the New York Stock Exchange the chief executive officer certification required by Section 303A.12(a) of the NYSE’s Listed Company Manual.

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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. 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 may 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;

• 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 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;

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• 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.

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

Reserve estimates depend on many assumptions that may prove to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated.

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 uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysic, engineering and production data. As a result, estimates of different engineers may vary. In addition, the extent, quality and reliability of this technical data can vary. The degree of uncertainty varies among the three regions in which we operate. The estimation of reserves in the Gulf Coast region requires more estimates than the East and West regions and inherently has more uncertainty surrounding reserve estimation. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. 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. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original

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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 prices 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 in Statement of Financial Accounting Standards No. 69 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.

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

We are continually identifying and evaluating opportunities to acquire natural gas and oil properties. We may not be able to successfully consummate any acquisition, to acquire producing natural gas and oil properties that contain economically recoverable reserves, or to integrate the properties into our operations profitably.

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

Our business involves a variety of operating risks, including:

• blowouts, cratering and explosions;

• mechanical problems;

• uncontrolled flows of natural gas, oil or well fluids;

• fires;

• formations with abnormal pressures;

• pollution and other environmental risks; and

• natural disasters.

In addition, we conduct operations in shallow offshore areas, which are subject to additional hazards of marine operations, such as capsizing, collision and damage from severe weather. 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.

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Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. As of December 31, 2005, we owned or operated approximately 3,400 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.

In accordance with customary industry practice, 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 and results of operations.

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. 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.

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, particularly in the Rocky Mountains, Mid-Continent and Gulf Coast areas. 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.

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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 2005 we primarily employed natural gas and crude oil price swap and collar agreements to attempt to manage price risk. 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. 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 is below the floor.

These hedging arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:

• a counterparty is unable to satisfy its obligations;

• production is less than expected; or

• there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.

We will continue to evaluate the benefit of 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 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.

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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. We also have adopted a stockholder rights plan. Because of our stockholder rights plan and these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent board of directors.

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

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 certificate of incorporation 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.

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ITEM 3. LEGAL PROCEEDINGS

We are a defendant in various legal proceedings arising in the normal course of our business. All known liabilities are accrued based on management’s best estimate of the potential loss. While the outcome and impact of such legal proceedings on us 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 our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

Wyoming Royalty Litigation

In January 2002, we were sued by 13 overriding royalty owners in Wyoming federal district court, as reported in previous filings. The plaintiffs made claims pertaining to deductions from their overriding royalty and claims concerning penalties for improper reporting. As a result of several decisions by the Court favorable to us, the case was settled in September 2005 with no payment from us and a dismissal with prejudice of all claims by plaintiffs. The settlement included provisions for reporting and payment going forward. In the third quarter of 2005, management reversed the reserve we had recorded regarding this case, which did not have a material impact on our consolidated financial statements.

West Virginia Royalty Litigation

In December 2001, we were sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification and allege that we failed to pay royalty based upon the wholesale market value of the gas, that we had taken improper deductions from the royalty and failed to properly inform royalty owners of the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that we reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings.

Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The Court entered an order on June 1, 2005 granting the motion for class certification. The parties have negotiated a modification to the order which will result in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and that will limit the claims to those arising on and after December 17, 1991. The Court has postponed the trial date from April 17, 2006, in light of a case pending before the West Virginia Supreme Court of Appeals which may decide issues of law that may apply to the issue of deductibility of post-production expenses. We intend to challenge the class certification order by filing a Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.

We are vigorously defending the case. We have established a reserve that management believes is adequate based on their estimate of the probable outcome of this case.

Texas Title Litigation

On January 6, 2003, we were served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their Second Supplemental Original Petition on November 12, 2004 and their Third Supplemental Original Petition on February 22, 2005 (which added Wynn-Crosby 1996, Ltd. and Dominion Oklahoma Texas Exploration & Production, Inc.). Plaintiffs allege that they are the owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. Cody Energy, LLC, our subsidiary, acquired certain leases and wells in 1997 and 1998.

The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in minerals and all improvements on the lands on which we acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. Plaintiffs claim that they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a claim of fraudulent concealment to avoid the affirmative defense of limitations. In August 2005, the case was abated until late February 2006, during which time the parties are allowed to amend pleadings or add additional parties to the litigation. Due to the abatement of the case, we have

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not had the opportunity to conduct discovery in this matter. We estimate that production revenue from this field since Cody Energy, LLC acquired title is approximately $15.7 million, and that the carrying value of this property is approximately $33.6 million.

Although the investigation into this claim continues, we intend to vigorously defend the case. Should we receive an adverse ruling in this case, an impairment review would be assessed to determine whether the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, we have not established a reserve for this matter.

Raymondville Area

In April 2004, our wholly owned subsidiary, Cody Energy, LLC, filed suit in state court in Willacy County, Texas against certain of its co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody had proposed a new prospect under the terms of the Joint Operating Agreement. Some of the co-working interest owners elected not to participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

The working interest owners who elected not to participate notified Cody that they believed that they had the right to participate in wells drilled after the initial well. Cody contends that the working interest owners that elected not to participate are required to assign their interest in the prospect to those who elected to participate. The defendants have filed a counter claim against the Company, and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville area.

Cody has signed a settlement agreement with certain of the defendants representing approximately 3% of the interest in the area. Cody and the remaining defendant filed cross motions for summary judgment. In August 2005, the trial judge entered an order granting Cody’s Motion for Summary Judgment requiring the remaining defendant to assign to Cody all of its interest in the prospect and to remove the lien filed against Cody’s interest. The defendant has filed a Motion for Reconsideration and Opposition to Proposed Order. The Court has not yet made a decision on these two motions.

Commitment and Contingency Reserves

We have established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that we could incur approximately $10.2 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

While the outcome and impact on us 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 our consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during the fourth quarter of 2005.

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EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information about our executive officers as of February 17, 2006, 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	52	Chairman, President and Chief Executive Officer	2001
Michael B. Walen	57	Senior Vice President, Exploration and Production	1998
Scott C. Schroeder	43	Vice President and Chief Financial Officer	1997
J. Scott Arnold	52	Vice President, Land and Associate General Counsel	1998
Robert G. Drake	58	Vice President, Information Services and Operational Accounting	1998
Abraham D. Garza	59	Vice President, Human Resources	1998
Jeffrey W. Hutton	50	Vice President, Marketing	1995
Thomas S. Liberatore	49	Vice President, Regional Manager, East Region	2003
Lisa A. Machesney	50	Vice President, Managing Counsel and Corporate Secretary	1995
Henry C. Smyth	59	Vice President, Controller and Treasurer	1998

All officers are elected annually by our Board of Directors. Except for the following, all of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years.

Dan O. Dinges joined Cabot Oil & Gas Corporation as President and Chief Operating Officer and as a member of the Board of Directors in September 2001. He was promoted to his current position of Chairman, President and Chief Executive Officer in May 2002. Mr. Dinges came to Cabot after a 20-year career with Samedan Oil Corporation, a subsidiary of Noble Affiliates, Inc. The last three years, Mr. Dinges served as Samedan’s Senior Vice President, as well as Division General Manager for the Offshore Division, a position he held since August 1996. He also served as a member of the Executive Operating Committee for Samedan. Mr. Dinges started his career as a Landman for Mobil Oil Corporation covering Louisiana, Arkansas and the central Gulf of Mexico. After four years of expanding responsibilities at Mobil, he joined Samedan as a Division Landman – Offshore. Over the years, Mr. Dinges held positions of increasing responsibility at Samedan including Division Manager, Vice President and ultimately Senior Vice President. Mr. Dinges received his B.B.A. degree in Petroleum Land Management from The University of Texas.

Thomas S. Liberatore joined Cabot in January 2002 as Regional Manager, East and was promoted to his current position in July 2003. Prior to joining the Company, Mr. Liberatore served as Vice President, Exploration and Production for North Coast Energy. He began his career as a geologist and has held various positions of increasing responsibility for Presidio Oil Company and Belden & Blake Corporation. Mr. Liberatore received his B.S. in Geology from West Virginia University.

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PART II

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

The 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 the 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. On February 28, 2005, we announced that our Board of Directors had declared a 3-for-2 split of our common stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, we paid cash based on the closing price of the common stock on the record date. All common stock accounts and per share data, including cash dividends per share, have been retroactively adjusted to give effect to the 3-for-2 split of our common stock.

	High		Low		Cash Dividends
2005
First Quarter	$	38.04	$	27.78	$	0.027
Second Quarter		38.13		28.29		0.040
Third Quarter		50.81		36.05		0.040
Fourth Quarter		51.54		40.48		0.040
2004
First Quarter	$	21.93	$	19.17	$	0.027
Second Quarter		28.20		20.09		0.027
Third Quarter		30.05		25.87		0.027
Fourth Quarter		32.25		27.27		0.027

As of January 31, 2006, there were 632 registered holders of the common stock. Shareholders include individuals, brokers, nominees, custodians, trustees, and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms.

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 2005	—	$	—	—	1,918,750
November 2005	207,400	$	43.10	207,400	1,711,350
December 2005	225,200	$	42.95	225,200	1,486,150
Total	432,600	$	43.02

On August 13, 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our common stock in the open market or in negotiated transactions. As a result of the 3-for-2 stock split effected in March 2005, this figure has been adjusted to three million shares. All purchases executed have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities.

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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, and the Consolidated Financial Statements and related Notes.

	Year Ended December 31,
(In thousands, except per share amounts)	2005		2004		2003		2002		2001
Statement of Operations Data
Operating Revenues	$	682,797	$	530,408	$	509,391	$	353,756	$	447,042
Impairment of Oil and Gas Properties (1)		—		3,458		93,796		2,720		6,852
Income from Operations		258,731		160,653		66,587		49,088		95,366
Net Income		148,445		88,378		21,132		16,103		47,084
Basic Earnings per Share (2)(3)	$	3.04	$	1.81	$	0.44	$	0.34	$	1.04
Dividends per Common Share (2)	$	0.147	$	0.107	$	0.107	$	0.107	$	0.107
Balance Sheet Data
Properties and Equipment, Net	$	1,238,055	$	994,081	$	895,955	$	971,754	$	981,338
Total Assets		1,495,370		1,210,956		1,055,056		1,100,947		1,092,810
Current Portion of Long-Term Debt		20,000		20,000		—		—		—
Long-Term Debt		320,000		250,000		270,000		365,000		393,000
Stockholders’ Equity		600,211		455,662		365,197		350,657		346,552

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

⁽²⁾ All Earnings per Share and Dividends per Common Share figures have been retroactively adjusted for the 3-for-2 split of our common stock effective March 31, 2005.

⁽³⁾ Year 2003 includes a cumulative effect of a change in accounting principle loss of $0.14 per share related to the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations.”

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

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

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.

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

OVERVIEW

Cabot Oil & Gas and its subsidiaries are a leading independent oil and gas company engaged in the exploration, development, acquisition, exploitation, production and marketing of natural gas, and to a lesser extent, crude oil and natural gas liquids from its properties in North America. We also transport, store, gather and produce natural gas for resale. Our 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.

At Cabot, there are three types of investment alternatives that constantly compete for available capital: drilling opportunities, acquisition opportunities and financial opportunities such as debt repayment or repurchase of common stock. 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.

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. Throughout 2004 and 2005, the futures market reported unprecedented natural gas and crude oil contract prices. Our realized natural gas and crude oil price was $6.74 per Mcf and $44.19 per Bbl, respectively, in 2005. These realized prices include the realized impact of derivative instruments. In an effort to manage commodity price risk, we entered into a series of crude oil and natural gas price collars and swaps. These financial instruments are an element of our risk management strategy but prevented us from realizing the full impact of the price environment.

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 demands, 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, natural gas liquids and crude oil prices, and therefore, we cannot determine 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.

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The tables below illustrate how natural gas prices have fluctuated by month over 2004 and 2005. “Index” represents the first of the month Henry Hub index price per Mmbtu. The “2004” and “2005” price is the natural gas price per Mcf realized by us and includes the realized impact of our natural gas price collar and swap arrangements, as applicable:

(in $ per Mcf)	Natural Gas Prices by Month - 2005
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	6.21	$	6.29	$	6.30	$	7.33	$	6.77	$	6.13	$	6.98	$	7.65	$	10.97	$	13.93	$	13.85	$	11.21
2005	$	5.78	$	5.84	$	5.52	$	6.28	$	6.19	$	5.55	$	6.05	$	6.58	$	7.76	$	8.94	$	8.53	$	7.78
(in $ per Mcf)	Natural Gas Prices by Month - 2004
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	6.15	$	5.77	$	5.15	$	5.37	$	5.94	$	6.68	$	6.14	$	6.04	$	5.08	$	5.79	$	7.63	$	7.78
2004	$	5.23	$	5.23	$	5.17	$	4.88	$	4.96	$	5.23	$	5.39	$	5.21	$	4.54	$	5.29	$	5.63	$	5.55

Prices for crude oil have followed a similar path as the commodity price continued to maintain strength in 2004 and rose further in 2005. The tables below contain the NYMEX monthly average crude oil price (Index) and our realized per barrel (Bbl) crude oil prices by month for 2004 and 2005. The “2004” and “2005” price is the crude oil price per Bbl realized by us and includes the realized impact of our crude oil derivative arrangements:

(in $ per Bbl)	Crude Oil Prices by Month - 2005
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	46.85	$	48.05	$	54.63	$	53.22	$	49.87	$	56.42	$	59.03	$	64.99	$	65.55	$	62.27	$	58.34	$	59.45
2005	$	38.18	$	40.57	$	47.30	$	44.95	$	41.88	$	44.58	$	46.24	$	46.62	$	45.05	$	45.92	$	45.59	$	43.70
(in $ per Bbl)	Crude Oil Prices by Month - 2004
	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec
Index	$	34.23	$	34.50	$	36.72	$	36.62	$	40.28	$	38.05	$	40.81	$	44.88	$	45.94	$	53.09	$	48.48	$	43.26
2004	$	30.62	$	30.66	$	31.62	$	30.97	$	30.80	$	31.51	$	31.43	$	33.00	$	31.61	$	32.87	$	33.15	$	30.46

We reported earnings of $3.04 per share, or $148.4 million, for 2005. This is up from the $1.81 per share, or $88.4 million, reported in 2004. The stronger price environment was a primary contributor to the earnings increase due to the increase in natural gas and oil revenues. Prices, including the realized impact of derivative instruments, rose 30% for natural gas and 40% for oil.

We drilled 316 gross wells with a success rate of 95% in 2005 compared to 256 gross wells with a 95% success rate in 2004. Total capital and exploration expenditures increased by $166.1 million to $425.6 million, of which $73.1 million was for property acquisitions, in 2005 compared to $259.5 million for 2004. We believe our operating cash flow in 2006 will be sufficient to fund our capital and exploration budgeted spending of approximately $396 million and again provide excess cash flow. Any excess cash flow may be used for acquisitions, to pay current debt due, repurchase common stock, expand our capital program or other opportunities.

Our 2006 strategy will remain consistent with 2005. We will remain focused on our strategies of balancing our capital investments between higher risk projects with the potential for higher returns and lower risk projects with more stable returns, along with balancing longer life investments with impact exploration opportunities. In the current year we have allocated our planned program for capital and exploration expenditures among our various operating regions. We believe these strategies are appropriate in 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.

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FINANCIAL CONDITION

Capital Resources and Liquidity

Our primary source of cash in 2005 was from funds generated from operations, as well as borrowings on our revolving credit facility and, to a lesser extent, proceeds from the exercise of stock options under our stock plans. 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 subject to seasonal influences characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout the recent years. Working capital is also substantially influenced by these variables. During 2005, approximately 1.4 Bcfe of expected production in our Gulf Coast region was deferred due to the impacts of Hurricanes Katrina and Rita. These hurricanes did not have a material adverse impact on our capital resources nor liquidity. Fluctuation 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 sales. Cash flows provided by operating activities were primarily used to fund exploration and development expenditures, purchase treasury stock and pay dividends. Proceeds from the exercise of stock options under stock option plans during 2005 partially offset our repurchase of 452,300 treasury shares of common stock at a weighted average purchase price of $42.41. See below for additional discussion and analysis of cash flow.

	Year-Ended December 31,
(In thousands)	2005			2004			2003
Cash Flows Provided by Operating Activities	$	364,560		$	273,022		$	241,638
Cash Flows Used by Investing Activities		(412,150	)		(255,357	)		(151,856	)
Cash Flows Provided / (Used) by Financing Activities		48,190			(8,363	)		(90,660	)
Net Increase / (Decrease) in Cash and Cash Equivalents	$	600		$	9,302		$	(878	)

Operating Activities. Net cash provided by operating activities in 2005 increased $91.5 million over 2004. This increase is primarily due to higher commodity prices. Key components impacting net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 30% over 2004, while crude oil realized prices increased 40% over the same period. Production volumes declined slightly, with a less than one percent reduction of equivalent production in 2005 compared to 2004. While we believe 2006 commodity production may exceed 2005 levels, 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.

Net cash provided by operating activities in 2004 increased $31.4 million over 2003. This increase is primarily due to higher commodity prices. Key components of net operating cash flows are commodity prices, production volumes and operating costs. Average realized natural gas prices increased 15% over 2003, while crude oil realized prices increased 7% over the same period. Production volumes declined, with a 5% reduction of equivalent production in 2004 compared to 2003. 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 by investing activities are capital spending and exploration expense. We establish the budget for these amounts based on our current estimate of future commodity prices. Due to the volatility of commodity prices, our capital expenditures may be periodically adjusted during any given year. Cash flows used in investing activities increased for the years ended December 31, 2005 and 2004 in the amounts of $156.8 million and $103.5 million, respectively. The increase from 2004 to 2005 is primarily due to an increase in drilling activity in the East region and the Rocky Mountains area of our West region in response to higher commodity prices. Our continued drilling activity in Canada also contributed to the increase. In addition, we spent $73.1 million in proved property acquisitions, primarily in the Gulf Coast. The increase from 2003 to 2004 was also primarily due to an increase in drilling activity in response to higher commodity prices. This increase largely occurred in our East region and the Rocky Mountains area of our West region. Our initial drilling activity in Canada also contributed to the increase.

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Financing Activities. Cash flows provided by financing activities were $48.2 million for the year ended December 31, 2005, resulting from borrowings under the credit facility, partially offset by the purchase of treasury stock and dividend payments. Cash flows used by financing activities for the year ended December 31, 2004 were $8.4 million. This is the result of proceeds from the exercise of stock options, offset by the purchase of treasury shares and dividend payments. Cash flows used by financing activities for the year ended December 31, 2003 were $90.7 million. This is substantially due to a net repayment on our revolving credit facility in the amount of $95.0 million. Cash utilized for the repayments was generated from operating cash flows.

At December 31, 2005, we had $90 million of debt outstanding under our credit facility. The credit facility provides for an available credit line of $250 million, which can be expanded up to $350 million, either with the existing banks or new banks. 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’ petroleum engineer) and other assets. The revolving term of the credit facility ends in December 2009. We strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. Management believes that we have the ability to finance through new debt or equity offerings, if necessary, our capital requirements, including potential acquisitions.

In August 1998, we announced that our Board of Directors authorized the repurchase of two million shares of our common stock in the open market or in negotiated transactions. As a result of the 3-for-2 stock split effected in March 2005, this figure has been adjusted to three million shares. During 2005, we repurchased 452,300 shares of our common stock at a weighted average price of $42.41. All purchases executed to date have been through open market transactions. There is no expiration date associated with the authorization to repurchase our securities. The maximum number of shares that may yet be purchased under the plan as of December 31, 2005 was 1,486,150. See Item 5 “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for additional information.

Capitalization

Information about our capitalization is as follows:

	December 31,
(In millions)	2005			2004
Debt (1)	$	340.0		$	270.0
Stockholders’ Equity		600.2			455.7
Total Capitalization	$	940.2		$	725.7
Debt to Capitalization		36	%		37	%
Cash and Cash Equivalents	$	10.6		$	10.0

⁽¹⁾ Includes $20.0 million of current portion of long-term debt at both December 31, 2005 and 2004. Includes $90 million of borrowings under our revolving credit facility at December 31, 2005. There were no borrowings under our revolving credit facility at December 31, 2004.

For the year ended December 31, 2005, we paid dividends of $7.2 million on our common stock. A regular dividend of $0.04 per share of common stock, or $0.027 per share for dividends prior to the 3-for-2 stock split as adjusted for the split, has been declared for each quarter since we became a public company.

Capital and Exploration Expenditures

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

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The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 2005.

(In millions)	2005		2004		2003
Capital Expenditures
Drilling and Facilities	$	249.3	$	174.0	$	102.0
Leasehold Acquisitions		22.1		18.3		14.1
Pipeline and Gathering		17.9		13.5		10.6
Other		1.4		1.6		1.8
		290.7		207.4		128.5
Proved Property Acquisitions		73.1		4.0		1.5
Exploration Expense		61.8		48.1		58.2
Total	$	425.6	$	259.5	$	188.2

We plan to drill about 391 gross wells in 2006 compared with 316 gross wells drilled in 2005. This 2006 drilling program includes approximately $396 million in total capital and exploration expenditures, down from $425.6 million in 2005. Capital and exploration expenditures in 2005 included a layer of $73.1 million in proved property acquisitions as shown in the table above. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.

There are many factors that impact our depreciation, depletion and amortization rate. These include reserve additions and revisions, development costs, impairments and changes in anticipated production in a future period. In 2006 management expects an increase in our depreciation, depletion and amortization rate due to negative reserve revisions and higher capital costs. This change may result in an increase of depreciation, depletion and amortization of 10% to 15% greater than 2005 levels. This increase will not have an impact on our cash flows.

Contractual Obligations

Our known 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, and we have not guaranteed the debt of any other party.

A summary of our known contractual obligations as of December 31, 2005 are set forth in the following table:

			Payments Due by Year
					2007		2009		2011 &
(In thousands)	Total		2006		to 2008		to 2010		Beyond
Long-Term Debt (1)	$	340,000	$	20,000	$	40,000	$	110,000	$	170,000
Interest on Long-Term Debt (2)		132,960		24,632		44,950		32,673		30,705
Firm Gas Transportation Agreements (3)		93,766		11,661		19,839		6,762		55,504
Drilling Rig Commitments (3)		104,315		26,055		68,585		9,675		—
Operating Leases		17,746		4,876		9,174		3,696		—
Total Contractual Cash Obligations	$	688,787	$	87,224	$	182,548	$	162,806	$	256,209

⁽¹⁾ Including current portion. At December 31, 2005, we had $90 million of outstanding debt on our revolving credit facility. See Note 4 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 $250 million long-term debt outstanding at December 31, 2005. Interest payments on the $90 million of outstanding borrowings on our revolving credit facility were calculated by assuming that the December 31, 2005 outstanding balance of $90 million will be outstanding through the 2009 maturity date and by assuming a constant interest rate of 7.25% which was the December 31, 2005 interest rate. Actual results will likely differ from these estimates and assumptions.

⁽³⁾ For further information on our obligations under firm gas transportation agreements and drilling rig commitments, see Note 7 of the Notes to the Consolidated Financial Statements.

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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, 2005 is $43.0 million.

Subsequent to December 31, 2005, we entered into an agreement for one additional drilling rig in the Gulf Coast. The total commitment over the next four years is $27.4 million, of which $0.8 million, $9.1 million, $9.1 million and $8.4 million will be paid out during the years 2006, 2007, 2008 and 2009, respectively.

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. The most significant policies are discussed below.

Oil and Gas Reserves

The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysic, engineering and production data. The extent, quality and reliability of this technical data can vary. The degree of uncertainty varies among the three regions in which we operate. The estimation of reserves in the Gulf Coast region requires more estimates than the East and West regions and inherently has more uncertainty surrounding reserve estimation. The differences in the reserve estimation process are substantially due to the geological conditions in which the wells are drilled. 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. The accuracy of a reserve estimate is a function of:

• the quality and quantity of available data;

• the interpretation of that data;

• the accuracy of various mandated economic assumptions; and

• the judgment of the persons preparing the estimate.

Since 1990, 100% of our reserves have been reviewed by Miller & Lents, Ltd., an independent oil and gas reservoir engineering consulting firm, who in their opinion determined the estimates presented to be reasonable in the aggregate. We have not been required to record a significant reserve revision in the past three years. For more information regarding reserve estimation, including historical reserve revisions, refer to the “Supplemental Oil and Gas Information.”

Our rate of recording depreciation, depletion and amortization expense (DD&A) is dependent upon our estimate of proved reserves, which is 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 non-economic 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 $0.05 to $0.06 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 $0.01 impact on our total DD&A rate. These estimated impacts are based on current data, and actual events could require different adjustments to DD&A.

In addition, a decline in proved reserve estimates may impact the outcome of our annual impairment test under Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” 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.

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Carrying Value of Oil and Gas Properties

We evaluate the impairment of our oil and gas properties on a lease-by-lease 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 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 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. In 2003, we significantly revised the estimated cash flow utilized in our impairment review of the Kurten field due to a loss of a reversionary interest in the field. In December 2003, our remaining interest in the field was sold. For additional discussion on the Kurten field impairment see Note 2 of the Notes to the Consolidated Financial Statements. In 2004 and 2005, there were no unusual or unexpected occurrences that caused significant revisions in estimated cash flows which were utilized in our impairment test.

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 regional basis and based on the estimated life of unproved property leasehold rights. Historically, the average property lives in each of the regions have not significantly changed. If the average unproved property life decreases or increases by one year, the amortization would increase by approximately $2.7 million or decrease by approximately $1.6 million, respectively per year.

In the past, the average leasehold life in the Gulf Coast region has been shorter than the average life in the East and West regions. Average property lives in the Gulf Coast, East and West regions have been four, seven and seven years, respectively. Average property lives in Canada are estimated to be six years. 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 program.

Accounting for Derivative Instruments and Hedging Activities

Periodically we enter into derivative commodity instruments to hedge our exposure to price fluctuations on natural gas and crude oil production. We follow the accounting prescribed in SFAS No. 133. Under SFAS No. 133, 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. Under SFAS No. 133, effectiveness is a measurement of how closely correlated the hedge instrument is with the underlying physical sale. For example, a natural gas price swap that converts Henry Hub index to a fixed price would be perfectly correlated, and 100% effective, if the underlying gas were sold at the Henry Hub index. Any portion of the gains or losses that are considered ineffective under the SFAS No. 133 test are recorded immediately as a component of Operating Revenue, either in Natural Gas Production or Crude Oil and Condensate Revenue, on the Statement of Operations.

Long-Term Employee Benefit Costs

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.

The current benefit service costs, as well as the existing liabilities, for pensions and other postretirement benefits are measured on a discounted present value basis. The discount rate is a current rate, related to the rate at which the liabilities could be settled. Our assumed discount rate is based on average rates of return published for a theoretical portfolio of high-quality fixed income securities. In order to select the discount rate, we use benchmarks such as the

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Moody’s Aa Corporate Rate, which was 5.48% annualized for 2005, and the Citigroup Pension Liability Index, which was 5.55% for 2005. We look to these benchmarks as well as considering durations of expected benefit payments. We have determined based on these assumptions that a discount rate of 5.5% at December 31, 2005 is reasonable.

In order to value our pension liabilities, we use the RP-2000 mortality table. This is a widely accepted table used for valuing pension liabilities. This table represents a more recent and conservative mortality table than the prior years’ 1983 Group Annuity Mortality Table, and appears to be an appropriate table based on the demographics of our benefit plans. Another consideration that is made is a salary scale selection. We have assumed that salaries will increase 4% based on our expectation of future salary increases.

The benefit obligation and the periodic cost of postretirement medical benefits also are measured based on assumed rates of future increase in the per capita cost of covered health care benefits. As of December 31, 2005, the assumed rate of increase was 9.0%. The net periodic cost of pension benefits included in expense also is affected by the expected long-term rate of return on plan assets assumption. The expected return on plan assets rate is normally changed less frequently than the assumed discount rate, and reflects long-term expectations, rather than current fluctuations in market conditions. The actual rate of return on plan assets may differ from the expected rate due to the volatility normally experienced in capital markets. Management’s goal is to manage the investments over the long term to achieve optimal returns with an acceptable level of risk and volatility.

We have established objectives regarding plan assets in the pension plan. In our pension calculations, we have used 8% as the expected long-term return on plan assets for 2005, 2004 and 2003. However, we expect to achieve a minimum 5% annual real rate of return on the total portfolio over the long term. We believe that this is a reasonable estimate based on our actual results. The actual rate of return on plan assets annualized over the past ten years is approximately 10%.

We generally target a portfolio of assets that are within a range of approximately 60% to 80% for equity securities and approximately 20% to 40% for fixed income securities. Large capitalization equities may make up a maximum of 65% of the portfolio. Small capitalization equities and international equities may make up a maximum of 30% and 15%, respectively, of the portfolio. Fixed income bonds may make up a maximum of 40% of our portfolio.

Stock-Based Compensation

Prior to the issuance of SFAS No. 123(R) “Share Based Payment (revised 2004)”, there were two alternative methods that could be used to account for stock-based compensation. The first method is the Intrinsic Value method and recognizes compensation cost as the excess, if any, of the quoted market price of our stock at the grant date over the amount an employee must pay to acquire the stock. The second method is the Fair Value method. Under the fair value method, compensation cost is measured at the grant date based on the value of an award and is recognized over the service period, which is usually the vesting period. As of December 31, 2005, we account for stock-based compensation in accordance with the Intrinsic Value method. SFAS No. 123(R) requires that the fair value of stock options and any other equity-based compensation must be expensed at the grant date. To calculate the fair value, either a binomial or Black-Scholes valuation model may be used. We currently expense performance share awards; however, beginning in the first quarter of 2006, we will be required to expense all stock-based compensation. Further discussion of SFAS No. 123(R) and stock compensation is included in “Recently Issued Accounting Pronouncements.”

On October 26, 2005, the Compensation Committee of our Board of Directors approved the acceleration to December 15, 2005 of the vesting of 198,799 unvested stock options awarded in February 2003 under our Second Amended and Restated 1994 Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under our 2004 Incentive Plan.

The 198,799 shares awarded to employees under the 1994 plan at an exercise price of $15.32 would have vested in February 2006. The 24,500 shares awarded to non-employee directors under the 2004 plan at an exercise price of $23.32 would have vested 12,250 shares in April 2006 and April 2007, respectively. The decision to accelerate the vesting of these unvested options, which we believed to be in the best interest of our shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with our adoption of SFAS No. 123(R).

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The accelerated vesting of the options did not have an impact on our results of operations or cash flows for 2005. The acceleration of vesting is expected to reduce our compensation expense related to these options by approximately $0.2 million for 2006.

OTHER ISSUES AND CONTINGENCIES

Corporate Income Tax. We have benefited in the past and may benefit in the future from the alternative minimum tax (AMT) relief granted under the Comprehensive National Energy Policy Act of 1992 (the Act). The Act repealed provisions of the AMT requiring a taxpayer’s alternative minimum taxable income to be increased on account of certain intangible drilling costs (IDC) and percentage depletion deductions for corporations other than integrated oil companies. The repeal of these provisions generally applies to taxable years beginning after 1992. The repeal of the excess IDC preference can not reduce a taxpayer’s alternative minimum taxable income by more than 40% of the amount of such income determined without regard to the repeal of such preference.

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 “Business” 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 the Company’s 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. At December 31, 2005, we are 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, the Company may apply for a temporary waiver with the lender, which, if granted, would allow us a period of time to remedy the situation. See further discussion in Capital Resources and Liquidity.

Limited Partnership. As part of the 2001 Cody acquisition, we acquired an interest in certain oil and gas properties in the Kurten field, as general partner of a partnership and as an operator. We had approximately a 25% interest in the field, including a one percent interest in the partnership. Under the partnership agreement, we had the right to a reversionary working interest that would bring our ultimate interest to 50% upon the limited partner reaching payout. Based on the addition of this reversionary interest, and because the field has over a 40-year reserve life, approximately $91 million was allocated to this field under purchase accounting at the time of the acquisition. Additionally, the limited partner had the sole option to trigger a liquidation of the partnership.

Effective February 13, 2003, liquidation of the partnership commenced at the election of the limited partner. The limited partner was a financial entity and not an industry operator. Their decision to liquidate was based upon their perception that the value of their investment in the partnership had increased due to an increase in underlying commodity prices, primarily oil, since their investment in 1999. We proceeded with the liquidation to avoid having a minority interest in a non-operated water flood field for which the new operator was not designated at the time of liquidation. In connection with the liquidation, an appraisal was required to be obtained to allocate the interest in the partnership assets. Additionally, we were required to test the field for recoverability in accordance with SFAS No. 144. Pursuant to the terms of the partnership agreement and based on the appraised value of the partnership assets it was not possible for us to obtain the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field, the limited partner’s decision and our decision to proceed with the liquidation, an impairment review was performed which required an impairment charge in the first quarter of 2003 of $87.9 million ($54.4 million after-tax). This impairment charge is reflected in the 2003 Statement of Operations as an operating expense but did not impact our cash flows.

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. During the past few years, we have invested a significant portion of our drilling dollars in the Gulf Coast, where insurance rates are significantly higher than in other regions such as the East.

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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, to a lesser extent, oil. Declines in oil and gas prices may have a material adverse effect on our financial condition, liquidity, 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 impact the outcome of our annual impairment test under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly large impact on our financial results.

The majority of our production is sold at market responsive prices. Generally, if the commodity indexes fall, 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 with the use of derivative financial instruments. Most recently, we have used financial instruments such as price collar and swap arrangements to reduce the impact of declining prices on our revenue. Under both arrangements, there is also risk that the movement of the index prices will result in the Company not being able to realize the full benefit of a market improvement.

Recently Issued Accounting Pronouncements

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in SFAS No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN No. 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN No. 47 is effective for fiscal years ending after December 15, 2005. Our financial position, results of operations and cash flows were not impacted by this Interpretation, since we currently record all asset retirement obligations.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. For our disclosures, refer to Note 2 of the Notes to the Consolidated Financial Statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections-A replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS No. 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion No. 20, the cumulative effect of voluntary changes in accounting principle

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was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion No. 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS No. 123(R) revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS No. 123(R) will be effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, we will not adopt this SFAS until the first quarter of 2006. We plan to use the modified prospective application method as detailed in SFAS No. 123(R). At this time, management does not believe that the adoption of SFAS No. 123(R) will materially impact our operating results, nor will there be any impact on our future cash flows. See “Stock-Based Compensation” below for further information.

In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, we are allowed to use the date the award is approved in accordance with our corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. We will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

In November 2005, the FASB issued FSP FAS 123(R)-3 “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which provides a simpler, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS No. 123(R). Under this FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS No. 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS No. 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that are partially vested or granted after the SFAS No. 123(R) adoption date will not be affected by this FSP and will be calculated in accordance with SFAS No. 123(R) which requires that only the excess tax benefit or deficiency of the tax deduction over the tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS No. 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS No. 123(R) for the calculation of the APIC pool. We will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

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In February 2006, the FASB issued FSP FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event.” Within certain share-based payment plans, a company can be required to settle outstanding options upon the occurrence of certain events, such as a change in control or liquidity of a company or the death or disability of the shareholder. This FSP amends paragraphs 32 and A229 of SFAS No. 123(R) to incorporate a probability assessment by a company. Under SFAS No. 123(R), it is required that options and similar instruments be classified as liabilities if the entity can be required under any circumstances to settle the instrument in cash or other assets. Under the FSP, a cash settlement feature that can be exercised only upon the occurrence of a contingent event that is outside of the employee’s control does not meet the criteria for liability classification, and should remain to be classified in equity, unless it becomes probable that the contingent event will occur. The effective date for the guidance in this FSP is upon the initial adoption of SFAS No. 123(R). We will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

*    *    *

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 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

2005 and 2004 Compared

We reported net income for the year ended December 31, 2005 of $148.4 million, or $3.04 per share. During 2004, we reported net income of $88.4 million, or $1.81 per share. Operating income increased by $98.0 million compared to the prior year, from $160.7 million to $258.7 million. The increase in operating income from 2004 to 2005 was principally due to an increase in natural gas and oil production revenues partially offset by an increase in total operating expenses. Net income increased from 2004 to 2005 by $60.0 million due to an increase in operating income partially offset by an increase of $37.6 million in income tax expense.

Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $6.74 per Mcf compared to $5.20 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments, which reduced these prices by $1.33 per Mcf in 2005 and $0.76 per Mcf in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $1.1 million and $0.9 million for the years ended December 31, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.

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	Year Ended December 31,					Variance
	2005			2004		Amount			Percent
Natural Gas Production (Mmcf)
Gulf Coast		28,071			31,358		(3,287	)	(10	)%
West		23,224			21,866		1,358		6	%
East		21,435			19,442		1,993		10	%
Canada		1,149			167		982		588	%
Total Company		73,879			72,833		1,046		1	%
Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	6.38		$	5.27	$	1.11		21	%
West	$	6.00		$	4.75	$	1.25		26	%
East	$	8.02		$	5.60	$	2.42		43	%
Canada	$	6.79		$	4.69	$	2.10		45	%
Total Company	$	6.74		$	5.20	$	1.54		30	%
Natural Gas Production Revenue (in thousands)
Gulf Coast	$	179,061		$	165,177	$	13,884		8	%
West		139,298			103,851		35,447		34	%
East		171,902			108,935		62,967		58	%
Canada		7,802			784		7,018		895	%
Total Company	$	498,063		$	378,747	$	119,316		32	%
Price Variance Impact on Natural Gas Production Revenue
(in thousands)
Gulf Coast	$	31,200
West		28,997
East		51,798
Canada		2,414
Total Company	$	114,409
Volume Variance Impact on Natural Gas Production Revenue (in thousands)
Gulf Coast	$	(17,317	)
West		6,448
East		11,170
Canada		4,606
Total Company	$	4,907

The increase in Natural Gas Production Revenue is due substantially to the increase in natural gas sales prices. In addition, the slight increase in production was due to the successful drilling programs in the East, West and Canada. Partially offsetting this was the decrease in the Gulf Coast production. The increase in the realized natural gas price combined with the increase in production resulted in a net revenue increase of $119.3 million.

41

Brokered Natural Gas Revenue and Cost

	Year Ended December 31,					Variance
	2005			2004		Amount			Percent
Sales Price ($/Mcf)	$	9.14		$	6.56	$	2.58		39	%
Volume Brokered (Mmcf)		10,793			12,876		(2,083	)	(16	)%
Brokered Natural Gas Revenues (in thousands)	$	98,605		$	84,416
Purchase Price ($/Mcf)	$	8.08		$	5.84	$	2.24		38	%
Volume Brokered (Mmcf)		10,793			12,876		(2,083	)	(16	)%
Brokered Natural Gas Cost (in thousands)	$	87,183		$	75,217
Brokered Natural Gas Margin (in thousands)	$	11,422		$	9,199	$	2,223		24	%
(in thousands)
Sales Price Variance Impact on Revenue	$	27,852
Volume Variance Impact on Revenue		(13,664	)
	$	14,188
(in thousands)
Purchase Price Variance Impact on Purchases	$	(24,130	)
Volume Variance Impact on Purchases		12,165
	$	(11,965	)

The increased brokered natural gas margin of $2.2 million was driven by an increased sales price that outpaced the increase in purchase cost, offset in part by a decrease in volume.

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Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price for 2005, including the realized impact of derivative instruments, was $44.19 per Bbl compared to $31.55 per Bbl for 2004. These prices include the realized impact of derivative instruments, which reduced these prices by $9.93 per Bbl in 2005 and $8.98 per Bbl in 2004. The following table excludes the unrealized gain from the change in derivative fair value of $5.5 million and the unrealized loss from the change in derivative fair value of $2.9 million for the years ended December 31, 2005 and 2004, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.

	Year Ended December 31,					Variance
	2005			2004		Amount			Percent
Crude Oil Production (Mbbl)
Gulf Coast		1,528			1,805		(277	)	(15	)%
West		166			159		7		4	%
East		27			27		—		—
Canada		18			4		14		350	%
Total Company		1,739			1,995		(256	)	(13	)%
Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	42.81		$	30.67	$	12.14		40	%
West	$	55.37		$	40.29	$	15.08		37	%
East	$	53.84		$	38.28	$	15.56		41	%
Canada	$	43.39		$	37.93	$	5.46		14	%
Total Company	$	44.19		$	31.55	$	12.64		40	%
Crude Oil Revenue (in thousands)
Gulf Coast	$	65,427		$	55,357	$	10,070		18	%
West		9,155			6,404		2,751		43	%
East		1,463			1,049		414		39	%
Canada		791			129		662		513	%
Total Company	$	76,836		$	62,939	$	13,897		22	%
Price Variance Impact on Crude Oil Revenue (in thousands)
Gulf Coast	$	18,547
West		2,496
East		423
Canada		100
Total Company	$	21,566
Volume Variance Impact on Crude Oil Revenue (in thousands)
Gulf Coast	$	(8,492	)
West		299
East		—
Canada		524
Total Company	$	(7,669	)

The increase in the realized crude oil price combined with the decline in production resulted in a net revenue increase of $13.9 million. The decrease in oil production is primarily the result of the decrease in the Gulf Coast region production due to the continued natural decline of the CL&F lease in south Louisiana, as well as the impact of hurricanes which included the shutting in and deferring of production at the Breton Sound offshore lease, one of our largest areas of offshore oil production.

43

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,
	2005						2004
	Realized			Unrealized			Realized			Unrealized
	(In thousands)
Operating Revenues - Increase/(Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	(98,223	)	$	1,114		$	(54,564	)	$	137
Crude Oil		(2,430	)		(6	)		—			6
Total Cash Flow Hedges		(100,653	)		1,108			(54,564	)		143
Other Derivative Financial Instruments
Natural Gas Production		—			—			(444	)		777
Crude Oil		(14,842	)		5,518			(17,908	)		(2,923	)
Total Other Derivative Financial Instruments		(14,842	)		5,518			(18,352	)		(2,146	)
	$	(115,495	)	$	6,626		$	(72,916	)	$	(2,003	)

We are exposed to market risk to the extent of changes in market prices of natural gas and 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.

Other Operating Revenues

Other operating revenues decreased $3.6 million. This change was primarily a result of an increase in our payout liability associated with the reduction of our interest due to customary reversionary interest owned by others, which correspondingly decreased other operating revenues. In addition, our revenues from net profits interest declined over the prior year. This revenue variance also results, to a lesser extent, from changes in our wellhead gas imbalances over the previous year.

Operating Expenses

Total costs and expenses from operations increased $54.5 million for the year ended December 31, 2005 compared to the year ended December 31, 2004. The primary reasons for this fluctuation are as follows:

• Exploration expense increased $13.7 million in 2005, primarily as a result of increased dry hole expenses partially offset by decreased spending on geological and geophysical expenses. During 2005, we spent $6.8 million less on geological and geophysical activities but incurred an additional $18.9 million in dry hole expense. In addition, we spent an additional $0.8 million on delay rentals. The increase in dry hole expense is mainly due to expenses incurred in the Gulf Coast and, to a smaller extent, in Canada and the West.

• Taxes Other Than Income increased by $13.3 million from 2004 compared to 2005, primarily due to increased production taxes as a result of increased commodity prices. Additionally, ad valorem and franchise taxes were higher compared to the prior year.

• Brokered Natural Gas Cost increased by $12.0 million from 2004 to 2005. See the preceding table labeled “Brokered Natural Gas Revenue and Cost” for further analysis.

• Direct Operations expense increased by $8.2 million. This is primarily the result of increased expenses for outside operated properties and workovers. In addition, there were increases over the prior year in maintenance charges, equipment expenses and employee related expenses.

• Depreciation, Depletion and Amortization increased by $5.1 million in 2005. This is primarily due to an increase in offshore DD&A rates associated with the commencement of offshore production in late 2004 and increased production in the East and West regions.

44

• Impairment of Oil and Gas Properties decreased by $3.5 million as we incurred no impairment expense in the current year. The costs incurred in the prior year related to a field in south Louisiana. Further analysis of this impairment is discussed in Note 2 of the Notes to the Consolidated Financial Statements.

• Impairment of Unproved Properties increased $2.8 million over the prior year. This is due to increased amortization related to unproved property additions both offshore and onshore, including an increase in our Canadian additions.

• General and Administrative expense increased by $2.9 million in 2005. This increase is primarily due to increased stock compensation expense relating to performance share awards, increased professional services fees and higher employee related expenses. Partially offsetting these increases was a decrease in miscellaneous expenses, primarily due to the reversal of the reserve attributable to litigation that was settled in the 2005 period.

Interest Expense, Net

Interest expense, net increased $0.1 million. Interest expense related to borrowings under our revolving credit facility was higher in the current year due to higher average borrowings. Average borrowings based on month end balances for the 2005 year were approximately $130 million compared to approximately $95 million in the prior year. In addition, the effective interest rate on the credit facility increased to 6.9% during 2005 from 4.2% during the prior year. Partially offsetting this was an increase in interest income on our short-term investments.

Income Tax Expense

Income tax expense increased $37.6 million due to an increase in our pre-tax net income.

2004 and 2003 Compared

We reported net income for the year ended December 31, 2004 of $88.4 million, or $1.81 per share. During 2003, we reported net income of $21.1 million, or $0.44 per share. Operating income increased by $94.1 million compared to the prior year, from $66.6 million to $160.7 million. The increase in net income and operating income was principally due to decreased operating expenses from 2003 to 2004 related to the decrease in impairments of oil and gas properties of $90.3 million related to the loss in 2003 of a reversionary interest in the Kurten field. In addition, the increases in operating income and net income were due to an increase in our realized natural gas and crude oil prices.

Natural Gas Production Revenues

Our average total company realized natural gas production sales price, including the realized impact of derivative instruments, was $5.20 per Mcf compared to $4.51 per Mcf for the comparable period of the prior year. These prices include the realized impact of derivative instruments which reduced these prices by $0.76 per Mcf in 2004 and $0.68 per Mcf in 2003. The following table excludes the unrealized gain from the change in derivative fair value of $0.9 million and the unrealized loss of $1.5 million for the years ended December 31, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Natural Gas Production Revenues line item in the Statement of Operations.

45

	Year Ended December 31,					Variance
	2004			2003		Amount			Percent
Natural Gas Production (Mmcf)
Gulf Coast		31,358			29,550		1,808		6	%
West		21,866			23,776		(1,910	)	(8	)%
East		19,442			18,580		862		5	%
Canada		167			—		167		—
Total Company		72,833			71,906		927		1	%
Natural Gas Production Sales Price ($/Mcf)
Gulf Coast	$	5.27		$	4.78	$	0.49		10	%
West	$	4.75		$	3.67	$	1.08		29	%
East	$	5.60		$	5.15	$	0.45		9	%
Canada	$	4.69		$	—	$	4.69		—
Total Company	$	5.20		$	4.51	$	0.69		15	%
Natural Gas Production Revenue (in thousands)
Gulf Coast	$	165,177		$	141,107	$	24,070		17	%
West		103,851			87,245		16,606		19	%
East		108,935			95,672		13,263		14	%
Canada		784			—		784		—
Total Company	$	378,747		$	324,024	$	54,723		17	%
Price Variance Impact on Natural Gas Production Revenue (in thousands)
Gulf Coast	$	15,434
West		23,613
East		8,828
Canada		784
Total Company	$	48,659
Volume Variance Impact on Natural Gas Production Revenue (in thousands)
Gulf Coast	$	8,635
West		(7,009	)
East		4,438
Canada		—
Total Company	$	6,064

The increase in natural gas production revenues was mainly a result of increased sales prices as well as the increase in overall production. Natural gas production was up slightly from the prior year and production revenues also increased from 2003. Natural gas production increased slightly in all regions except the West region, where the decline in production was due to lower capital spending in 2003 and continued natural decline. The increases in both sales price and production resulted in an increase in natural gas production revenues of $54.7 million.

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Brokered Natural Gas Revenue and Cost

	Year Ended December 31,					Variance
	2004			2003		Amount			Percent
Sales Price ($/Mcf)	$	6.56		$	5.16	$	1.40		27	%
Volume Brokered (Mmcf)		12,876			18,557		(5,681	)	(31	)%
Brokered Natural Gas Revenues (in thousands)	$	84,416		$	95,754
Purchase Price ($/Mcf)	$	5.84		$	4.64	$	1.20		26	%
Volume Brokered (Mmcf)		12,876			18,557		(5,681	)	(31	)%
Brokered Natural Gas Cost (in thousands)	$	75,217		$	86,104
Brokered Natural Gas Margin (in thousands)	$	9,199		$	9,650	$	(451	)	(5	)%
(in thousands)
Sales Price Variance Impact on Revenue	$	18,026
Volume Variance Impact on Revenue		(29,363	)
	$	(11,337	)
(in thousands)
Purchase Price Variance Impact on Purchases	$	(15,451	)
Volume Variance Impact on Purchases		26,338
	$	10,887

The decrease in brokered natural gas revenues of $11.3 million combined with the decline in brokered natural gas cost of $10.9 million resulted in a decrease to the brokered natural gas margin of $0.5 million.

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Crude Oil and Condensate Revenues

Our average total company realized crude oil sales price, including the realized impact of derivative instruments, was $31.55 per Bbl compared to $29.55 per Bbl for 2003. These prices include the realized impact of derivative instruments, which reduced these prices by $8.98 per Bbl in 2004 and $1.41 per Bbl in 2003. The following table excludes the unrealized loss from the change in derivative fair value of $2.9 million and $1.9 million for the years ended December 31, 2004 and 2003, respectively. These unrealized changes in fair value have been included in the Crude Oil and Condensate Revenues line item in the Statement of Operations.

	Year Ended December 31,					Variance
	2004			2003		Amount			Percent
Crude Oil Production (Mbbl)
Gulf Coast		1,805			2,591		(786	)	(30	)%
West		159			188		(29	)	(15	)%
East		27			27		—		—
Canada		4			—		4		—
Total Company		1,995			2,806		(811	)	(29	%)
Crude Oil Sales Price ($/Bbl)
Gulf Coast	$	30.67		$	29.48	$	1.19		4	%
West	$	40.29		$	30.11	$	10.18		34	%
East	$	38.28		$	32.65	$	5.63		17	%
Canada	$	37.93		$	—	$	37.93		—
Total Company	$	31.55		$	29.55	$	2.00		7	%
Crude Oil Revenue (in thousands)
Gulf Coast	$	55,357		$	76,375	$	(21,018	)	(28	%)
West		6,404			5,675		729		13	%
East		1,049			870		179		21	%
Canada		129			—		129		—
Total Company	$	62,939		$	82,920	$	(19,981	)	(24	%)
Price Variance Impact on Crude Oil Revenue (in thousands)
Gulf Coast	$	2,151
West		1,604
East		179
Canada		129
Total Company	$	4,063
Volume Variance Impact on Crude Oil Revenue (in thousands)
Gulf Coast	$	(23,169	)
West		(875	)
East		—
Canada		—
Total Company	$	(24,044	)

The decline in crude oil production is due to emphasis on natural gas in the Gulf Coast drilling program, along with the natural decline of existing production in south Louisiana. The increase in the realized crude oil price combined with the decline in production resulted in a net revenue decrease of $20.0 million.

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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,
	2004						2003
	Realized			Unrealized			Realized			Unrealized
	(In thousands)
Operating Revenues - Increase/(Decrease) to Revenue
Cash Flow Hedges
Natural Gas Production	$	(54,564	)	$	137		$	(48,829	)	$	(691	)
Crude Oil		—			6			(2,973	)		32
Total Cash Flow Hedges		(54,564	)		143			(51,802	)		(659	)
Other Derivative Financial Instruments
Natural Gas Production		(444	)		777			—			(777	)
Crude Oil		(17,908	)		(2,923	)		(990	)		(1,911	)
Total Other Derivative Financial Instruments		(18,352	)		(2,146	)		(990	)		(2,688	)
	$	(72,916	)	$	(2,003	)	$	(52,792	)	$	(3,347	)

We are exposed to market risk to the extent of changes in market prices of natural gas and 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.

Other Operating Revenues

Other operating revenues decreased $3.7 million. This change was primarily a result of decreases in natural gas transportation revenue and natural gas liquid revenue for the year ended December 31, 2004.

Operating Expenses

Total costs and expenses from operations decreased $85.3 million for the year ended December 31, 2004 compared to the year ended December 31, 2003. The primary reasons for this fluctuation are as follows:

• Brokered Natural Gas Cost decreased $10.9 million. For additional information related to this decrease see the analysis performed for Brokered Natural Gas Revenue and Cost.

• Exploration expense decreased $10.0 million primarily as a result of higher dry hole expense in 2003. During 2004, we drilled 5 dry exploratory wells compared to 15 in the corresponding period of 2003.

• Depreciation, Depletion and Amortization increased, as anticipated, by approximately 9% or $8.4 million. The increase was primarily due to negative reserve revisions in south Louisiana in 2003, which increased the per Mcfe DD&A rate in 2004.

• Impairment of Oil and Gas Properties expense decreased $90.3 million. This decrease is substantially related to a pre-tax non-cash impairment charge of $87.9 million incurred in 2003 related to the loss of a reversionary interest in the Kurten field. Effective February 13, 2003, the Kurten partnership commenced liquidation at the limited partner’s election. In connection with the liquidation, an appraisal was obtained to allocate the interest in the partnership assets. Based on the receipt of the appraisal in February 2003, we determined that we would not receive the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field, we performed an impairment review which resulted in an $87.9 million charge.

• General and Administrative expense increased $9.6 million from 2003 to 2004. Stock compensation expense increased by $4.9 million as a result of performance share awards issued in 2004 and increased amortization of restricted stock grants for grants which occurred during the year. Compliance fees related to Sarbanes-Oxley increased expenses by $2.3 million, and there was a $1.2 million increase in employee related expenses.

• Taxes Other Than Income increased $3.9 million as a result of higher commodity prices realized during the year 2004 as compared to the prior year.

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Interest Expense, Net

Interest expense decreased $1.7 million. This variance is due to a lower average level of outstanding debt on the revolving credit facility offset somewhat by an increase in Prime rates. Average daily borrowings under the revolving credit facility during the year were $0.5 million in 2004 which is a decrease from $0.7 million in 2003. Our other remaining debt is at fixed interest rates.

Income Tax Expense

Income tax expense increased $35.2 million due to an increase in our pre-tax net income.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 10 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. Under our revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At December 31, 2005, we had nine cash flow hedges open: eight natural gas price collar arrangements and one crude oil price collar arrangement. At December 31, 2005, a $20.7 million ($12.9 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a $22.4 million short-term derivative liability and a $1.7 million short-term derivative receivable, which is shown in Other Current Assets on the Balance Sheet. The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate.

Assuming no change in commodity prices, after December 31, 2005 we would expect to reclassify to the Statement of Operations, over the next 12 months, $12.9 million in after-tax charges associated with commodity hedges. This reclassification represents the net liability associated with open positions currently not reflected in earnings at December 31, 2005 related to anticipated 2006 production.

Hedges on Production - Swaps

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 derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and 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 2005, natural gas price swaps covered 20,557 Mmcf, or 28% of our gas production, fixing the sales price of this gas at an average of $5.14 per Mcf.

At December 31, 2005, we had no open natural gas price swap contracts covering 2006 production.

From time to time, we enter into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS No. 133. These financial instruments are recorded at fair value at the balance sheet date. At December 31, 2005, we did not have any of these types of arrangements.

50

Hedges on Production - Options

From time to time, we enter into natural gas and crude oil collar 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 the collar arrangements, if the index price rises above the ceiling price, we pay the counterparty. If the index price falls below the floor price, the counterparty pays us. During 2005, natural gas price collars covered 15,157 Mmcf of our gas production, or 21% of our gas production with a weighted average floor of $5.59 per Mcf and a weighted average ceiling of $8.61 per Mcf. During 2005, an oil price collar covered 365 Mbbl of our crude oil production, or 21% of our crude oil production with a weighted average floor of $40.00 per Mbbl and a weighted average ceiling of $50.50 per Mbbl.

At December 31, 2005, we had open natural gas price collar contracts covering our 2006 production as follows:

	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted Average Ceiling / Floor		Net Unrealized Loss (In thousands)
As of December 31, 2005
First Quarter 2006	6,702	$	12.74 / $8.25
Second Quarter 2006	6,776		12.74 / 8.25
Third Quarter 2006	6,850		12.74 / 8.25
Fourth Quarter 2006	6,851		12.74 / 8.25
Full Year 2006	27,179	$	12.74 / $8.25	$	(20,425	)

At December 31, 2005, we had one open crude oil price collar contract covering our 2006 production as follows:

	Crude Oil Price Collar
Contract Period	Volume in Mbbl	Weighted Average Ceiling / Floor		Net Unrealized Loss (In thousands)
As of December 31, 2005
First Quarter 2006	90	$	76.00 / $50.00
Second Quarter 2006	91		76.00 / 50.00
Third Quarter 2006	92		76.00 / 50.00
Fourth Quarter 2006	92		76.00 / 50.00
Full Year 2006	365	$	76.00 / $50.00	$	(317	)

We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.

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.

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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. The Company uses available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” and does not impact our financial position, results of operations or cash flows.

Long-Term Debt

	December 31, 2005				December 31, 2004
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt
7.19% Notes	$	60,000	$	62,938	$	80,000	$	87,770
7.26% Notes		75,000		81,713		75,000		85,849
7.36% Notes		75,000		83,990		75,000		87,111
7.46% Notes		20,000		23,083		20,000		23,804
Credit Facility		90,000		90,000		—		—
	$	320,000	$	341,724	$	250,000	$	284,534

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	54
Consolidated Statement of Operations for the Years Ended December 31, 2005, 2004 and 2003	56
Consolidated Balance Sheet at December 31, 2005 and 2004	57
Consolidated Statement of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003	58
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2005, 2004 and 2003	59
Consolidated Statement of Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003	60
Notes to the Consolidated Financial Statements	61
Supplemental Oil and Gas Information (Unaudited)	89
Quarterly Financial Information (Unaudited)	93

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have completed integrated audits of Cabot Oil & Gas Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005, and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes 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. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 11 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” effective January 1, 2003.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

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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

March 6, 2006

55

CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(In thousands, except per share amounts)

	Year Ended December 31,
	2005		2004			2003
OPERATING REVENUES
Natural Gas Production	$	499,177	$	379,661		$	322,556
Brokered Natural Gas		98,605		84,416			95,816
Crude Oil and Condensate		82,348		60,022			81,040
Other		2,667		6,309			9,979
		682,797		530,408			509,391
OPERATING EXPENSES
Brokered Natural Gas Cost		87,183		75,217			86,162
Direct Operations - Field and Pipeline		61,750		53,581			50,399
Exploration		61,840		48,130			58,119
Depreciation, Depletion and Amortization		108,458		103,343			94,903
Impairment of Unproved Properties		12,966		10,145			9,348
Impairment of Oil & Gas Properties (Note 2)		—		3,458			93,796
General and Administrative		37,650		34,735			25,112
Taxes Other Than Income		54,293		41,022			37,138
		424,140		369,631			454,977
Gain / (Loss) on Sale of Assets		74		(124	)		12,173
INCOME FROM OPERATIONS		258,731		160,653			66,587
Interest Expense and Other		22,497		22,029			23,545
Income Before Income Taxes and Cumulative Effect of Accounting Change		236,234		138,624			43,042
Income Tax Expense		87,789		50,246			15,063
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE		148,445		88,378			27,979
CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 11)		—		—			(6,847	)
NET INCOME	$	148,445	$	88,378		$	21,132
Basic Earnings Per Share - Before Accounting Change	$	3.04	$	1.81		$	0.58
Diluted Earnings Per Share - Before Accounting Change	$	2.99	$	1.79		$	0.58
Basic Loss Per Share - Accounting Change	$	—	$	—		$	(0.14	)
Diluted Loss Per Share - Accounting Change	$	—	$	—		$	(0.14	)
Basic Earnings Per Share	$	3.04	$	1.81		$	0.44
Diluted Earnings Per Share	$	2.99	$	1.79		$	0.44
				—
Weighted Average Common Shares Outstanding		48,856		48,733			48,074
Diluted Common Shares (Note 12)		49,725		49,339			48,435

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED BALANCE SHEET

(In thousands, except share amounts)

	December 31,
	2005			2004
ASSETS
Current Assets
Cash and Cash Equivalents	$	10,626		$	10,026
Accounts Receivable		168,248			125,754
Inventories		24,616			24,049
Deferred Income Taxes		15,674			21,345
Other		11,148			13,505
Total Current Assets		230,312			194,679
Properties and Equipment, Net (Successful Efforts Method)		1,238,055			994,081
Deferred Income Taxes		19,587			14,855
Other Assets		7,416			7,341
	$	1,495,370		$	1,210,956
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable	$	140,006		$	104,969
Current Portion of Long-Term Debt		20,000			20,000
Deferred Income Taxes		941			944
Derivative Contracts		22,478			38,368
Accrued Liabilities		35,159			32,608
Total Current Liabilities		218,584			196,889
Long-Term Debt		320,000			250,000
Deferred Income Taxes		289,381			247,376
Other Liabilities		67,194			61,029
Commitments and Contingencies (Note 7)
Stockholders’ Equity
Common Stock:
Authorized — 80,000,000 Shares of $.10 Par Value Issued — 50,081,983 Shares and 49,680,915 Shares in 2005 and 2004, respectively		5,008			4,968
Additional Paid-in Capital		397,349			380,125
Retained Earnings		252,167			110,935
Accumulated Other Comprehensive Loss		(15,115	)		(20,351	)
Less Treasury Stock, at Cost:
1,513,850 and 1,061,550 Shares in 2005 and 2004, respectively		(39,198	)		(20,015	)
Total Stockholders’ Equity		600,211			455,662
	$	1,495,370		$	1,210,956

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

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CABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	148,445		$	88,378		$	21,132
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Cumulative Effect of Accounting Change		—			—			6,847
Depreciation, Depletion and Amortization		108,458			103,343			94,903
Impairment of Unproved Properties		12,966			10,145			9,348
Impairment of Oil & Gas Properties		—			3,458			93,796
Deferred Income Tax Expense		39,628			31,769			(9,837	)
(Gain) / Loss on Sale of Assets		(74	)		124			(12,173	)
Exploration Expense		61,840			48,130			58,119
Unrealized Change in Derivative Fair Value		(6,626	)		2,003			3,347
Performance Share Compensation		3,357			3,429			—
Stock-Based Compensation Expense and Other		6,446			3,475			885
Changes in Assets and Liabilities:
Accounts Receivable		(42,494	)		(39,404	)		(17,397	)
Inventories		(567	)		(5,808	)		(2,989	)
Other Current Assets		1,188			3,255			(9,208	)
Other Assets		(192	)		(491	)		163
Accounts Payable and Accrued Liabilities		29,803			17,231			7,041
Other Liabilities		2,382			3,985			(2,339	)
Net Cash Provided by Operating Activities		364,560			273,022			241,638
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures		(351,306	)		(207,346	)		(122,018	)
Proceeds from Sale of Assets		996			119			28,281
Exploration Expense		(61,840	)		(48,130	)		(58,119	)
Net Cash Used by Investing Activities		(412,150	)		(255,357	)		(151,856	)
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt		265,000			187,000			248,655
Decrease in Debt		(195,000	)		(187,000	)		(341,000	)
Sale of Common Stock Proceeds		4,586			12,474			6,728
Purchase of Treasury Stock		(19,183	)		(15,631	)		—
Dividends Paid		(7,213	)		(5,206	)		(5,043	)
Net Cash Provided / (Used) by Financing Activities		48,190			(8,363	)		(90,660	)
Net Increase / (Decrease) in Cash and Cash Equivalents		600			9,302			(878	)
Cash and Cash Equivalents, Beginning of Period		10,026			724			1,602
Cash and Cash Equivalents, End of Period	$	10,626		$	10,026		$	724

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

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C ABOT OIL & GAS CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In thousands)

	Common Shares	Stock Par		Treaury Shares	Treasury Stock			Paid-In Capital		Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Total
Balance at December 31, 2002	48,200	$	4,820	454	$	(4,384	)	$	351,486	$	(12,939	)	$	11,674		$	350,657
Net Income														21,132			21,132
Exercise of Stock Options	517		52						7,716								7,768
Cash Dividends at $0.16 per Share														(5,043	)		(5,043	)
Other Comprehensive Loss											(10,196	)					(10,196	)
Stock Grant Vesting	90		9						870								879
Balance at December 31, 2003	48,807	$	4,881	454	$	(4,384	)	$	360,072	$	(23,135	)	$	27,763		$	365,197
Net Income														88,378			88,378
Exercise of Stock Options	794		79						15,034								15,113
Purchase of Treasury Stock				608		(15,631	)										(15,631	)
Performance Share Awards									2,394								2,394
Stock Grant Vesting	80		8						2,625								2,633
Cash Dividends at $0.16 per Share														(5,206	)		(5,206	)
Other Comprehensive Income											2,784						2,784
Balance at December 31, 2004	49,681	$	4,968	1,062	$	(20,015	)	$	380,125	$	(20,351	)	$	110,935		$	455,662
Net Income														148,445			148,445
Exercise of Stock Options	300		30						8,217								8,247
Purchase of Treasury Stock				452		(19,183	)										(19,183	)
Performance Share Awards									4,147								4,147
Stock Grant Vesting	101		10						4,860								4,870
Cash Dividends at $0.16 per Share														(7,213	)		(7,213	)
Other Comprehensive Income											5,236						5,236
Balance at December 31, 2005	50,082	$	5,008	1,514	$	(39,198	)	$	397,349	$	(15,115	)	$	252,167		$	600,211

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

(In thousands)

	Year Ended December 31,
	2005			2004			2003
Net Income	$	148,445		$	88,378		$	21,132
Other Comprehensive Income / (Loss)
Reclassification Adjustment for Settled Contracts		100,653			53,516			47,926
Changes in Fair Value of Hedge Positions		(92,559	)		(48,494	)		(63,014	)
Minimum Pension Liability		(205	)		(1,404	)		(1,333	)
Foreign Currency Translation Adjustment		808			662			(5	)
Deferred Income Tax		(3,461	)(1)		(1,496	)(2)		6,230	(3)
Total Other Comprehensive Income / (Loss)		5,236			2,784			(10,196	)
Comprehensive Income	$	153,681		$	91,162		$	10,936

⁽¹⁾ Deferred income tax of ($3.5) million at December 31, 2005 represents the net deferred tax liability of approximately ($38.4) million on the Reclassification Adjustment for Settled Contracts, approximately $35.3 million on the Changes in Fair Value of Hedge Positions, approximately less than $0.1 million on the Minimum Pension Liability Adjustment and approximately ($0.3) million on the Foreign Currency Translation Adjustment.

⁽²⁾ Deferred income tax of ($1.5) million at December 31, 2004 represents the net deferred tax liability of approximately ($20.4) million on the Reclassification Adjustment for Settled Contracts, approximately $18.5 million on the Changes in Fair Value of Hedge Positions, approximately $0.6 million on the Minimum Pension Liability Adjustment and ($0.2) million on the Foreign Currency Translation Adjustment.

⁽³⁾ Deferred income tax of $6.2 million at December 31, 2003 represents the net deferred tax liability of approximately ($18.3) million on the Reclassification Adjustment for Settled Contracts, approximately $24.0 million on the Changes in Fair Value of Hedge Positions, approximately $0.5 million on the Minimum Pension Liability Adjustment and approximately less than $0.1 million on the Foreign Currency Translation Adjustment.

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 exploration, development, production and marketing of natural gas and, to a lesser extent, crude oil and 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 exploration and exploitation, exclusively within the continental United States and Canada. The Company’s exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. The Company’s program is designed to be disciplined and balanced with a focus on achieving strong financial returns.

The consolidated financial statements contain the accounts of the Company and its majority-owned subsidiaries after eliminating all significant intercompany balances and transactions. Certain prior year amounts have been reclassified to conform to the current year presentation.

On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s common stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the common stock on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s common stock.

Recently Issued Accounting Pronouncements

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN No. 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN No. 47 is effective for fiscal years ending after December 15, 2005. The Company’s financial position, results of operations and cash flows were not impacted by this Interpretation, since all asset retirement obligations are currently recorded.

On April 4, 2005, the FASB issued FASB Staff Position (FSP) FAS 19-1 “Accounting for Suspended Well Costs.” This staff position amends FASB Statement No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies who use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the Staff Position requires the annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. For the Company’s disclosures, refer to Note 2 of the Notes to the Consolidated Financial Statements.

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In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections-A replacement of APB Opinion No. 20 and FASB Statement No. 3.” In order to enhance financial reporting consistency between periods, SFAS No. 154 modifies the requirements for the accounting and reporting of the direct effects of changes in accounting principles. Under APB Opinion No. 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB Opinion No. 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change is required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in accounting principle and that disclosure of the preferability of the change is required. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005.

In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” SFAS No. 123(R) revises SFAS No. 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services provided by employee to employer. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model, and either a binomial or Black-Scholes model may be used. During the first quarter of 2005, the Securities and Exchange Commission (SEC) approved a new rule for public companies to delay the adoption of this standard. In April 2005, the SEC took further action to amend Regulation S-X to state that the provisions of SFAS No. 123(R) will be effective beginning with the first annual or interim reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005 for all non-small business issuers. As a result, the Company will not adopt this SFAS until the first quarter of 2006. The Company plans to use the modified prospective application method as detailed in SFAS No. 123(R). At this time, management does not believe that the adoption of SFAS No. 123(R) will materially impact the Company’s operating results, nor will there be any impact on future cash flows. See “Stock-Based Compensation” below for further information.

In October 2005, the FASB issued FSP FAS 123(R)-2, “Practical Accommodation to the Application of Grant Date as defined in FASB Statement No. 123(R).” This FSP provides guidance on the definition and practical application of “grant date” as described in SFAS No. 123(R). The grant date is described as the date that the employee and employer have met a mutual understanding of the key terms and conditions of an award. The other elements of the definition of grant date are: 1) the award must be authorized, 2) the employer must be obligated to transfer assets or distribute equity instruments so long as the employee has provided the necessary service and 3) the employee is affected by changes in the company’s stock price. To determine the grant date, the Company is allowed to use the date the award is approved in accordance with its corporate governance requirements so long as the three elements described above are met. Furthermore, the recipient cannot negotiate the award’s terms and conditions with the employer and the key terms and conditions of the award are communicated to all recipients within a reasonably short time period from the approval date. The Company will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

In November 2005, the FASB issued FSP FAS 123(R)-3 “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards,” which provides a simpler, more practical transition election relating to the calculation of the “APIC pool.” The APIC pool is defined as the pool of excess tax benefits available to absorb tax deficiencies occurring after the adoption of SFAS No. 123(R). Under this FSP, companies can elect to perform simpler computations to derive the beginning balance of the APIC pool as well as the impact on the APIC pool of fully vested and outstanding awards as of the SFAS No. 123(R) adoption date. The beginning balance can be computed by taking the sum of all tax benefits incurred prior to the adoption of SFAS No. 123(R) from stock-based compensation plans less the tax effected (using a blended statutory rate) pro forma stock-based compensation cost. In addition, increases to the APIC pool for fully vested awards can be calculated by multiplying the tax rate times the tax benefit of the deduction. The calculation of any awards that are partially vested or granted after the SFAS No. 123(R) adoption date will not be affected by this FSP and will be calculated in accordance with SFAS No. 123(R)

62

which requires that only the excess tax benefit or deficiency of the tax deduction over the tax effect of the compensation cost recognized should be considered for the APIC pool. Also under the FSP, all tax benefits recognized on fully vested awards and the excess tax benefits for partially vested and new awards will be reported on the Statement of Cash Flows as a component of financing activities. Companies will have up to one year after adopting SFAS No. 123(R) to decide to elect and disclose whether they plan to use the alternative method or the original method prescribed in SFAS No. 123(R) for the calculation of the APIC pool. The Company will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

In February 2006, the FASB issued FSP FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event.” Within certain share-based payment plans, a company can be required to settle outstanding options upon the occurrence of certain events, such as a change in control or liquidity of a company or the death or disability of the shareholder. This FSP amends paragraphs 32 and A229 of SFAS No. 123(R) to incorporate a probability assessment by a company. Under SFAS No. 123(R), it is required that options and similar instruments be classified as liabilities if the entity can be required under any circumstances to settle the instrument in cash or other assets. Under the FSP, a cash settlement feature that can be exercised only upon the occurrence of a contingent event that is outside of the employee’s control does not meet the criteria for liability classification, and should remain to be classified in equity, unless it becomes probable that the contingent event will occur. The effective date for the guidance in this FSP is upon the initial adoption of SFAS No. 123(R). The Company will adopt this FSP in conjunction with the adoption of SFAS No. 123(R).

Inventories

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

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 value of the natural gas imbalance is included in inventory in the consolidated balance sheet.

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. A determination of whether a well has found proved reserves is made shortly after drilling is completed. The determination is based on a process which relies on interpretations of available geologic, geophysic, 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 expense.

In the absence of a determination as to whether the reserves that have been found can be classified as proved, the costs of drilling such an exploratory well is not carried as an asset for more than one year following completion of drilling. If, after that year has passed, a determination that proved reserves exist cannot be made, the well is assumed

63

to be impaired, and its costs are charged to expense. Its costs can, however, continue to be capitalized if a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility.

The impairment of unamortized capital costs is measured at a lease level and is reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value. The Company determines if an impairment has occurred through either adverse changes or as a result of the annual review of all fields. In 2003, the Company recorded impairments related to the loss of a reversionary interest in its Kurten field and a field in the East region. These impairments totaled $93.8 million. During 2004, the Company recorded total impairments of $3.5 million. During 2005, the Company did not record any impairments.

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. The costs of unproved oil and gas properties are generally combined and impaired over a period that is based on the average holding period for such properties and the Company’s experience of successful drilling. 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 amortized over 12 to 25 years, gathering and compression equipment is amortized over 10 years and storage equipment and facilities are amortized 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 years.

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

Revenue Recognition and Gas Imbalances

The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded at the actual price realized upon the gas sale in accounts payable in the consolidated balance sheet if the Company’s excess takes of natural gas exceed its estimated remaining proved developed reserves for these properties. See Note 3 of the Notes to the Consolidated Financial Statements for the Company’s wellhead gas imbalances.

Brokered Natural Gas Margin

The revenues and expenses related to brokering natural gas are reported gross as part of Operating Revenues and Operating Expenses. The Company realizes brokered margin as a result of buying and selling natural gas in back-to-back transactions. The Company realized $11.4 million, $9.2 million, and $9.7 million of brokered natural gas margin in 2005, 2004, and 2003, respectively.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. 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.

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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.

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, as a component of Accounts Payable on the Balance Sheet. There were no credit balances from outstanding checks in zero balance cash accounts included in accounts payable at December 31, 2005 and 2004 as sufficient cash was available for offset.

Allowance for Doubtful Accounts

The Company records an allowance for doubtful accounts for receivables that the Company feels may be uncollectible based on the specific identification basis. The allowance for doubtful accounts, which is netted against the accounts receivable line on the Balance Sheet, was $5.6 million and $5.3 million at December 31, 2005 and 2004, respectively.

Risk Management Activities

From time to time, the Company enters into derivative contracts, such as natural gas and crude oil price swaps or costless price collars, as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. All hedge transactions are subject to the Company’s risk management policy which does not permit trading activities. Gains or losses on these hedging activities are generally recognized over the period that its inventories, 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 would be recognized currently in the results of operations.

When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. For example, in the case of natural gas price hedges, the gain or loss is reflected in natural gas revenue. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if the hedge is no longer effective, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 10 of the Notes to the Consolidated Financial Statements for further discussion.

Stock Based Compensation

The Company accounts for stock-based compensation in accordance with the intrinsic value based method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees.” Under the intrinsic value based method, the Company records no compensation expense for stock options granted when the exercise price for options granted is equal to the fair value of the Company’s common stock on the date of the grant.

SFAS No. 123, “Accounting for Stock-Based Compensation”, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”, outlines a fair value based method of accounting for stock options or similar equity instruments.

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The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation. The Earnings per Share amounts for prior periods have been retroactively adjusted to reflect the 3-for-2 split of the Company’s common stock effective March 31, 2005.

	Year Ended December 31,
(In thousands, except per share amounts)	2005		2004		2003
Net Income, as reported	$	148,445	$	88,378	$	21,132
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax, previously not included in Net Income		967		1,571		1,950
Pro forma Net Income	$	147,478	$	86,807	$	19,182
Earnings per Share:
Basic - as reported	$	3.04	$	1.81	$	0.44
Basic - pro forma	$	3.02	$	1.78	$	0.40
Diluted - as reported	$	2.99	$	1.79	$	0.44
Diluted - pro forma	$	2.97	$	1.76	$	0.40
Weighted Average Common Shares Outstanding		48,856		48,733		48,074
Diluted Common Shares		49,725		49,339		48,435

The fair value of stock options included in the pro forma results for each of the three years is not necessarily indicative of future effects on net income and earnings per share. As of January 1, 2006, the Company will adopt SFAS No. 123(R), as discussed above in the “Recently Issued Accounting Pronouncements” section.

On October 26, 2005, the Compensation Committee of the Board of Directors of the Company approved the acceleration to December 15, 2005 of the vesting of 198,799 unvested stock options awarded in February 2003 under the Company’s Second Amended and Restated 1994 Long-Term Incentive Plan and 24,500 unvested stock options awarded in April 2004 under the Company’s 2004 Incentive Plan.

The 198,799 shares awarded to employees under the 1994 plan at an exercise price of $15.32 would have vested in February 2006. The 24,500 shares awarded to non-employee directors under the 2004 plan at an exercise price of $23.32 would have vested 12,250 shares in April 2006 and April 2007, respectively. The decision to accelerate the vesting of these unvested options, which the Company believed to be in the best interest of its shareholders and employees, was made solely to reduce compensation expense and administrative burden associated with the Company’s adoption of SFAS No. 123(R). The accelerated vesting of the options did not have an impact on the Company’s results of operations or cash flows in 2005. The acceleration of vesting is expected to reduce the Company’s compensation expense related to these options by approximately $0.2 million for 2006.

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The assumptions used in the fair value method calculation as well as additional stock based compensation information are disclosed in the following table.

	Year Ended December 31,
(In thousands, except per share amounts)	2005		2004			2003
Compensation Expense in Net Income, as reported (1)	$	5,965	$	4,043		$	1,001
Weighted Average Value per Option Granted During the Period (2) (3)	$	—	$	11.31		$	6.77
Assumptions (3)
Stock Price Volatility		—		38.4	%		35.3	%
Risk Free Rate of Return		—		3.3	%		2.5	%
Dividend Rate (per year)	$	0.147	$	0.107		$	0.107
Expected Term (in years)		4		4			4

⁽¹⁾ Compensation expense is defined as expense related to the vesting of stock grants, net of tax. Compensation expense for the years ended December 31, 2005 and 2004 also includes $2.1 million and $2.0 million, respectively, net of tax related to performance shares.

⁽²⁾ Calculated using the Black-Scholes fair value based method.

⁽³⁾ There were no stock options issued during the year ended December 31, 2005.

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. At December 31, 2005, and 2004, the cash and cash equivalents are primarily concentrated in two financial institutions. The Company periodically assesses the financial condition of these institutions and believes that any possible credit risk is minimal.

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.

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 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, as well as estimates of expenses related to legal, environmental and other contingencies, depreciation, depletion and amortization, pension and postretirement obligations and deferred income taxes. Actual results could differ from those estimates.

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2. Properties and Equipment

Properties and equipment are comprised of the following:

	December 31,
(In thousands)	2005			2004
Unproved Oil and Gas Properties	$	107,787		$	94,795
Proved Oil and Gas Properties		1,970,407			1,646,841
Gathering and Pipeline Systems		178,876			160,951
Land, Building and Improvements		4,892			4,860
Other		33,077			31,261
		2,295,039			1,938,708
Accumulated Depreciation, Depletion and Amortization		(1,056,984	)		(944,627	)
	$	1,238,055		$	994,081

As of January 1, 2005, the Company adopted FSP FAS 19-1, “Accounting for Suspended Well Costs.” Upon adoption of the FSP, the Company evaluated all existing capitalized exploratory well costs under the provisions of the FSP. For further details on the provisions of this FSP, see Note 1 of the Notes to the Consolidated Financial Statements. The following table reflects the net changes in capitalized exploratory well costs during 2005, 2004 and 2003.

	December 31,
(In thousands)	2005			2004			2003
Beginning balance at January 1	$	8,591		$	3,681		$	3,757
Additions to capitalized exploratory well costs pending the determination of proved reserves		6,132			8,591			3,681
Reclassifications to wells, facilities, and equipment based on the determination of proved reserves		(1,069	)		(3,395	)		(2,881	)
Capitalized exploratory well costs charged to expense		(7,522	)		(286	)		(876	)
Ending balance at December 31	$	6,132		$	8,591		$	3,681

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)	2005		2004		2003
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	6,132	$	8,591	$	3,681
Capitalized exploratory well costs that have been capitalized for a period greater than one year		—		—		—
Balance at December 31	$	6,132	$	8,591	$	3,681
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		—		—		—

At December 31, 2005 and 2003, the Company had no wells that had completed drilling and a determination of whether proved reserves existed could not be made.

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At December 31, 2004, the Company had 3 wells that had completed drilling and a determination of whether proved reserves existed could not be made. One well was in the Rocky Mountains area and reached total depth in November 2004. It could not be completed due to the Bureau of Land Management stipulation which prohibited activity until the summer of 2005. Two wells in Canada completed drilling in October and December 2004. These wells were awaiting completion or sidetracking which was anticipated to commence by May 2005. Additional operations were performed on each of these wells, and all were determined to be unsuccessful. In 2005, $8.0 million was charged to expense for these wells, which was made up of $3.1 million for the Rocky Mountains area well and $4.9 million for the two wells in Canada.

During 2005, the Company did not record any impairments. During 2004, the Company recorded an impairment of $3.5 million. The impairment was recorded on a two-well field in south Louisiana and was due to production performance issues related to water encroachment. This impairment charge was recorded due to the capitalized cost of the field exceeding the future undiscounted cash flows. This charge is reflected in the operating results of the Company and was measured based on discounted cash flows utilizing a discount rate appropriate for risks associated with the related field.

As part of the 2001 Cody acquisition, we acquired an interest in certain oil and gas properties in the Kurten field, as general partner of a partnership and as an operator. We had approximately a 25% interest in the field, including a one percent interest in the partnership. Under the partnership agreement, we had the right to a reversionary working interest that would bring our ultimate interest to 50% upon the limited partner reaching payout. Based on the addition of this reversionary interest, and because the field has over a 40-year reserve life, approximately $91 million was allocated to this field under purchase accounting at the time of the acquisition. Additionally, the limited partner had the sole option to trigger a liquidation of the partnership.

Effective February 13, 2003, liquidation of the partnership commenced at the election of the limited partner. In connection with the liquidation, an appraisal was required to be obtained to allocate the interest in the partnership assets. Additionally, the Company was required to test the field for recoverability in accordance with SFAS No. 144. Pursuant to the terms of the partnership agreement and based on the appraised value of the partnership assets it was not possible for us to obtain the reversionary interest as part of the liquidation. Due to the impact of the loss of the reversionary interest on future estimated net cash flows of the Kurten field, the limited partner’s decision and our decision to proceed with the liquidation, an impairment review was performed which required an impairment charge in 2003 of $87.9 million ($54.4 million after-tax). This impairment charge is reflected in the 2003 Statement of Operations as an operating expense but did not impact our cash flows.

During 2003 the Company divested of certain non-strategic assets. The primary assets sold included properties in Pennsylvania that were sold for $16.1 million, and resulted in a gain of $6.9 million. Additionally, the Company divested of a water treatment facility in the amount of $3.4 million, which resulted in a gain of $2.5 million.

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

	December 31,
(In thousands)	2005			2004
Accounts Receivable
Trade Accounts	$	147,016		$	105,378
Joint Interest Accounts		14,319			13,554
Current Income Tax Receivable		12,239			10,796
Other Accounts		315			1,312
		173,889			131,040
Allowance for Doubtful Accounts		(5,641	)		(5,286	)
	$	168,248		$	125,754
Inventories
Natural Gas and Oil in Storage	$	18,279		$	17,631
Tubular Goods and Well Equipment		7,161			6,387
Pipeline Imbalances		(824	)		31
	$	24,616		$	24,049
Other Current Assets
Derivative Contracts	$	1,736		$	2,906
Drilling Advances		2,169			6,180
Prepaid Balances		6,939			4,173
Other Accounts		304			246
	$	11,148		$	13,505
Accounts Payable
Trade Accounts	$	18,227		$	12,808
Natural Gas Purchases		12,208			8,669
Royalty and Other Owners		49,312			35,369
Capital Costs		37,489			26,203
Taxes Other Than Income		10,329			5,634
Drilling Advances		5,760			7,102
Wellhead Gas Imbalances		2,175			1,991
Other Accounts		4,506			7,193
	$	140,006		$	104,969
Accrued Liabilities
Employee Benefits	$	9,020		$	10,123
Taxes Other Than Income		16,188			14,191
Interest Payable		6,818			6,569
Other Accounts		3,133			1,725
	$	35,159		$	32,608
Other Liabilities
Postretirement Benefits Other Than Pension	$	6,517		$	4,717
Accrued Pension Cost		5,904			5,089
Rabbi Trust Deferred Compensation Plan		4,883			4,199
Accrued Plugging and Abandonment Liability		42,991			40,375
Other Accounts		6,899			6,649
	$	67,194		$	61,029

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4. Debt and Credit Agreements

7.19% Notes

In November 1997, the Company issued an aggregate principal amount of $100 million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional investors in a private placement offering. The 7.19% Notes require five annual $20 million principal payments starting in November 2005, and the Company made its first $20 million payment during 2005. The Company may prepay all or any portion of the indebtedness on any date with a prepayment penalty. The 7.19% 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. These covenants include a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0, and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.

7.33% Weighted Average Fixed Rate Notes

To partially fund the cash portion of the acquisition of Cody Company in August 2001, the Company issued $170 million of Notes to a group of seven institutional investors in a private placement transaction in July 2001. Prior to the determination of the Note’s interest rates, the Company entered into a treasury lock in order to reduce the risk of rising interest rates. Interest rates rose during the pricing period, resulting in a $0.7 million gain that is being amortized over the life of the Notes, and thereby reducing the effective interest rate by 5.5 basis points. All of 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	%

The Notes were issued under the same Note Purchase Agreement as the 7.19% Notes.

Revolving Credit Agreement

On December 10, 2004, the Company amended its Revolving Credit Agreement (credit facility) with a group of nine banks. The credit facility allows for borrowings of $250 million, of which $90 million was outstanding at December 31, 2005. The facility can be expanded up to $350 million, either with the existing banks or new banks. This credit facility is unsecured. The term of the credit facility expires in December 2009. The available credit line is subject to adjustment from time to time on the basis of the projected present value (as determined by the banks’ petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. 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, the Company has a period of six months to reduce its outstanding debt to the adjusted credit line available with a requirement to provide additional borrowing base assets or pay down one-sixth of the excess during each of the six months.

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 is 50% or greater, greater than 75% or greater than 90% of the Company’s debt limit of $530 million, which can be expanded up to $630 million, as shown below.

	Debt Percentage
	Lower than 50%		50% or higher but not exceeding 75%		Higher than 75% but not exceeding 90%		Higher than 90%
Euro-Dollar margin	1.000	%	1.250	%	1.500	%	1.750	%
Base Rate margin	0.000	%	0.000	%	0.250	%	0.500	%

The Company’s effective interest rates for the credit facility in the years ended December 31, 2005, 2004, and 2003 were 6.9%, 4.2% and 1.9%, respectively. As of December 31, 2005, the weighted average interest rate on the Company’s credit facility was 7.25%. As of December 31, 2004, the Company had no borrowings outstanding on its credit facility. The credit facility provides for a commitment fee on the unused available balance at an annual rate of one-quarter of 1%. The credit facility also contains various customary restrictions, which include the following:

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

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(b) 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.

The Company was in compliance with all covenants contained in its various debt agreements at December 31, 2005 and 2004 and during the years then ended.

5. Employee Benefit Plans

Pension Plan

The Company has a non-contributory, defined benefit pension plan for all full-time employees. Plan benefits are based primarily on years of service and salary level near retirement. Plan assets are mainly fixed income investments and equity securities. The Company complies with the Employee Retirement Income Security Act (ERISA) of 1974 and Internal Revenue Code limitations when funding the plan. The measurement date used to measure pension benefit amounts is December 31, 2005.

The Company has a non-qualified equalization plan to ensure payments to certain executive officers of amounts to which they are already entitled under the provisions of the pension plan, but which are subject to limitations imposed by federal tax laws. This plan is unfunded.

Components of Net Periodic Benefit Cost

Net periodic pension cost of the Company during the last three years is comprised of the following:

(In thousands)	2005			2004			2003
Qualified
Current Year Service Cost	$	2,485		$	1,619		$	1,481
Interest Cost		1,896			1,697			1,515
Expected Return on Plan Assets		(1,507	)		(1,474	)		(999	)
Amortization of Prior Service Cost		99			88			88
Recognized Net Actuarial Loss		921			383			415
Net Periodic Pension Cost	$	3,894		$	2,313		$	2,500
(In thousands)	2005			2004			2003
Non-Qualified
Current Year Service Cost	$	(682	)	$	395		$	280
Interest Cost		85			381			163
Amortization of Prior Service Cost		77			77			77
Recognized Net Actuarial (Gain) / Loss		(22	)		428			187
Net Periodic Pension (Income) / Cost	$	(542	)	$	1,281		$	707

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Obligations and Funded Status

The following table illustrates the funded status of the Company’s pension plans at December 31:

	2005						2004
(In thousands)	Qualified			Non-Qualified			Qualified			Non-Qualified
Actuarial Present Value of:
Accumulated Benefit Obligation	$	29,669		$	1,204		$	23,181		$	3,579
Projected Benefit Obligation	$	39,449		$	1,762		$	29,809		$	6,257
Fair Value of Plan Assets		23,765			—			18,092			—
Projected Benefit Obligation in Excess of Plan Assets		15,684			1,762			11,717			6,257
Unrecognized Net Actuarial Loss		(14,899	)		(498	)		(9,846	)		(4,374	)
Unrecognized Prior Service Cost		(269	)		(245	)		(248	)		(322	)
Adjustment to Recognize Minimum Liability		5,388			185			3,466			2,018
Accrued Pension Cost	$	5,904		$	1,204		$	5,089		$	3,579

The change in the combined projected benefit obligation of the Company’s qualified and non-qualified pension plans during the last three years is explained as follows:

(In thousands)	2005			2004			2003
Beginning of Year	$	36,066		$	33,547		$	26,042
Service Cost		1,803			2,014			1,761
Interest Cost		1,981			2,078			1,678
Actuarial Loss		1,852			1,798			4,679
Plan Amendments		120			—			—
Benefits Paid		(611	)		(3,371	)		(613	)
End of Year	$	41,211		$	36,066		$	33,547

The change in the qualified plan assets at fair value of the Company’s pension plan during the last three years is explained as follows:

(In thousands)	2005			2004			2003
Beginning of Year	$	18,092		$	18,683		$	10,279
Actual Return on Plan Assets		1,544			957			2,446
Employer Contribution		5,000			2,000			6,735
Benefits Paid		(611	)		(3,371	)		(613	)
Expenses Paid		(260	)		(177	)		(164	)
End of Year	$	23,765		$	18,092		$	18,683

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The reconciliation of the combined funded status of the Company’s qualified and non-qualified pension plans at the end of the last three years is explained as follows:

(In thousands)	2005			2004			2003
Funded Status (1)	$	17,446		$	17,974		$	14,864
Unrecognized Net Actuarial Loss		(15,397	)		(14,220	)		(12,540	)
Unrecognized Net Prior Service Cost		(514	)		(570	)		(735	)
Net Amount Recognized	$	1,535		$	3,184		$	1,589
Accrued Benefit Liability - Qualified Plan	$	5,904		$	5,089		$	2,664
Accrued Benefit Liability - Non-Qualified Plan		1,204			3,579			3,171
Intangible Asset		(454	)		(570	)		(735	)
Accumulated Other Comprehensive Income		(5,119	)		(4,914	)		(3,511	)
Net Amount Recognized	$	1,535		$	3,184		$	1,589

⁽¹⁾ The qualified and non-qualified pension plans are in an under-funded position for 2005, 2004 and 2003 as the projected benefit obligation exceeds the plan assets.

Additional Information

The amounts included in Other Comprehensive Income as a result of increases in the minimum liability of the Company’s pension plans are as follows as of December 31:

(In thousands)	2005			2004			2003
Qualified Plan	$	1,900		$	2,199		$	(870	)
Non-Qualified Plan		(1,695	)		(795	)		2,203

Assumptions

Assumptions used to determine projected pension benefit obligations are as follows:

	2005		2004		2003
Discount Rate	5.50	%	5.75	%	6.25	%
Rate of Compensation Increase	4.00	%	4.00	%	4.00	%

Assumptions used to determine net periodic pension costs are as follows:

	2005		2004		2003
Discount Rate	5.75	%	6.25	%	6.50	%
Expected Long-Term Return on Plan Assets	8.00	%	8.00	%	8.00	%
Rate of Compensation Increase	4.00	%	4.00	%	4.00	%

The long-term expected rate of return on plan assets used in 2005, as shown above, is eight percent. 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.

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Plan Assets

At December 31, 2005 and 2004, the non-qualified pension plan did not have plan assets. The plan assets of the Company’s qualified pension plan at December 31, 2005 and 2004, by asset category are as follows:

	2005				2004
(In thousands)	Amount		Percent		Amount		Percent
Equity securities	$	19,556	82	%	$	13,934	77	%
Debt securities		840	4	%		3,226	18	%
Other (1)		3,369	14	%		932	5	%
Total	$	23,765	100	%	$	18,092	100	%

⁽¹⁾ Primarily consists of cash and cash equivalents.

The Company’s investment strategy for benefit plan assets is to invest in funds to maximize the return over the long-term, subject to an appropriate level of risk. Additionally, the objective is for each class of investments to outperform its representative benchmark over the long term. The Company generally targets a portfolio of assets that are within a range of approximately 60% to 80% for equity securities and approximately 20% to 40% for fixed income securities.

Cash Flows

Contributions

The funding levels of the pension plans are in compliance with standards set by applicable law or regulation. In 2005 the Company did not have any required minimum funding obligations; however, it chose to fund $5 million into the plan. In 2006 the Company does not have any required minimum funding obligations for the qualified pension plan. The Company will fund less than $0.1 million, as shown below, for the non-qualified pension plan. Currently, management has not determined if any discretionary funding will be made in 2006.

Estimated Future Benefit Payments

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

(In thousands)	Qualified		Non-Qualified		Total
2006	$	828	$	42	$	870
2007		848		54		902
2008		916		74		990
2009		1,106		85		1,191
2010		1,256		176		1,432
Years 2011 - 2015		10,878		1,418		12,296

Postretirement Benefits Other than Pensions

In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 245 retirees and their dependants at the end of 2005 and 251 retirees and their dependants at the end of 2004. The measurement date used to measure postretirement benefits other than pensions is December 31, 2005.

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When the Company adopted SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pension”, 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 amortization benefit of the unrecognized transition obligation amount below are the effects of plan amendments during 1996, 2000 and 2004. The remaining unamortized balance is $3.9 million which will be amortized over the next six years.

Components of Net Periodic Benefit Cost

Postretirement benefit costs recognized during the last three years are as follows:

(In thousands)	2005			2004			2003
Current Year Service Cost	$	675		$	671		$	265
Interest Cost		605			784			385
Recognized Net Actuarial Gain		(79	)		(59	)		(155	)
Amortization of Prior Service Cost		910			1,211			—
Amortization of Net Obligation at Transition		648			662			662
Total Postretirement Benefit Cost	$	2,759		$	3,269		$	1,157

Obligations and Funded Status

The funded status of the Company’s postretirement benefit obligation at December 31, 2005, 2004 and 2003 is comprised of the following:

(In thousands)	2005			2004			2003
Beginning of Year (1)	$	14,101		$	6,181		$	6,185
Service Cost		675			671			265
Interest Cost		605			784			386
Amendments		(1,434	)		6,901			—
Actuarial (Gain) / Loss		(876	)		864			221
Benefits Paid		(1,278	)		(1,300	)		(876	)
End of Year (1)	$	11,793		$	14,101		$	6,181

⁽¹⁾ The postretirement plan is in an under-funded position for 2005, 2004 and 2003 since the projected benefit obligation exceeds the plan assets. The postretirement plan does not have any plan assets.

The change in the accumulated postretirement benefit obligation during the last three years is presented as follows:

(In thousands)	2005			2004			2003
Fair Value of Plan Assets	$	—		$	—		$	—
Funded Status		11,793			14,101			6,181
Unrecognized Net Gain		2,475			814			1,736
Unrecognized Net Prior Service Cost		(3,366	)		(5,691	)		—
Unrecognized Net Transition Obligation		(3,888	)		(4,631	)		(5,293	)
Accrued Postretirement Benefit Liability	$	7,014		$	4,593		$	2,624

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Assumptions

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

	2005		2004		2003
Discount Rate(1)	5.50	%	5.75	%	6.25	%
Health Care Cost Trend Rate for Medical Benefits Assumed for Next Year	9.00	%	10.00	%	8.00	%
Rate to which the cost trend rate is assumed to decline (the Ultimate Trend Rate)	5.00	%	5.00	%	N/A
Year that the rate reaches the Ultimate Trend Rate	2010		2009		2009

⁽¹⁾ Represents the year end rates used to determine the projected benefit obligation. To compute postretirement cost in 2005, 2004 and 2003, respectively, the beginning of year discount rates of 5.75%, 6.25% and 6.50% were used.

The health care cost trend rate used to measure the expected cost from 2000 to 2003 for medical benefits to retirees was 8%. Provisions of the plan existing at that time would have prevented significant future increases in employer cost after 2000. During the years ended December 31, 2005 and 2004, the plan was amended in several areas effective January 1, 2006. As of January 1, 2006, coverage provided to participants age 65 and older will be under a fully-insured arrangement which replaces the former self-funded plan. Benefits under this new arrangement are expected to be comparable to benefits under the self-funded plan. The Company subsidy will be limited to 60% of the expected annual fully-insured premium. For all participants of any age, the Company subsidy for all retiree medical and prescription drug benefits, beginning January 1, 2006, is limited to an aggregate annual amount not to exceed $648,000. This limit will increase by 3.5% annually thereafter. Additionally, in February 2005, the Company purchased individual life insurance policies on a fully insured basis for all retirees retiring before January 1, 2006. Effective January 1, 2006, postretirement life insurance benefits will not be provided to new retirees.

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	$	12	$	(13	)
Effect on postretirement benefit obligation		131		(147	)

Cash Flows

Contributions

The Company expects to contribute approximately $0.6 million to the postretirement benefit plan in 2006.

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)
2006	$	571
2007		579
2008		580
2009		594
2010		616
Years 2011 - 2015		3,894

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On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to certain Medicare benefits. In accordance with FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, 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 the Company has amended the postretirement benefit plan to exclude prescription drug benefits to participants age 65 and older effective January 1, 2006, management believes this FSP will not have an 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 $1.6 million, $1.4 million and $1.4 million in 2005, 2004, and 2003, respectively. The Company matches employee contributions dollar-for-dollar on the first 6% of an employee’s pretax earnings. The Company’s common stock is an investment option within the SIP.

Deferred Compensation Plan

In 1998, the Company established a Deferred Compensation Plan. This plan is available to officers of the Company and acts as a supplement to the Savings Investment Plan. If the employee’s base salary and bonus deferrals cause the employee to not receive the full 6% company match to the Savings Investment Plan, the Company will make a contribution annually into the Deferred Compensation Plan to ensure that the employee receives a full matching contribution from the Company. Unlike the SIP, the Deferred Compensation Plan does not have dollar limits on tax deferred contributions. However, the assets of this 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. At December 31, 2005, the balance in the Deferred Compensation Plan’s rabbi trust was $4.9 million.

The employee participants guide the diversification of trust assets. The trust assets are invested in mutual funds that cover the investment spectrum from equity to money market. These mutual funds are publicly quoted and reported at market value. No shares of the Company’s stock are held by the trust. Settlement payments are made to participants in cash, either in a lump sum or in periodic installments. The market value of the trust assets is recorded on the Company’s balance sheet as a component of Other Assets and the corresponding liability is recorded as a component of Other Liabilities.

There is no impact on earnings or earnings per share from the changes in market value of the deferred compensation plan assets for two reasons. First, 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. Second, no shares of the Company’s stock are held in the trust.

The Company charged to expense plan contributions of less than $20,000 in each year presented.

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6. Income Taxes

Income tax expense (benefit) is summarized as follows:

	Year Ended December 31,
(In thousands)	2005		2004			2003
Current
Federal	$	42,976	$	14,767		$	22,826
State		5,185		3,710			2,075
Total		48,161		18,477			24,901
Deferred
Federal		37,565		31,779			(8,549	)
State		2,063		(10	)		(1,289	)
Total		39,628		31,769			(9,838	)
Total Income Tax Expense	$	87,789	$	50,246		$	15,063

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

	Year Ended December 31,
(In thousands)	2005			2004			2003
Statutory Federal Income Tax Rate		35	%		35	%		35	%
Computed “Expected” Federal Income Tax	$	82,682		$	48,518		$	15,065
State Income Tax, Net of Federal Income Tax Benefit		7,030			4,353			1,334
Other, Net		(1,923	)(1)		(2,625	)(2)		(1,336	)(3)
Total Income Tax Expense	$	87,789		$	50,246		$	15,063

⁽¹⁾ Other, Net includes credit adjustments of $1.3 million related to the qualified production activities deduction, $0.6 million related to the recognition of benefit for federal statutory depletion in excess of basis, $1.0 million related to the recognition of benefit for state statutory depletion in excess of basis, $0.6 million related to the reduction of the state statutory rate and other permanent items. Other, Net also includes debit adjustments of $0.7 million related to excess compensation, $0.7 million related to Internal Revenue Service audit adjustments and other permanent items.

⁽²⁾ Other, Net includes credit adjustments of $1.6 million related to the recognition of benefit for federal statutory depletion in excess of basis, $0.9 million related to the recognition of benefit for state statutory depletion in excess of basis, and other permanent items.

⁽³⁾ Other, Net includes credit adjustments of $0.8 million related to the recognition of benefit for state statutory depletion in excess of basis and $0.5 million related to the recognition of a benefit for a state net operating loss.

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The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets as of December 31 were as follows:

	Year Ended December 31,
(In thousands)	2005		2004
Deferred Tax Liabilities
Property, Plant and Equipment	$	288,602	$	246,962
Items Accrued for Financial Reporting Purposes		1,720		1,358
Total		290,322		248,320
Deferred Tax Assets
Net Operating Loss Carryforwards		2,591		2,045
Items Accrued for Financial Reporting Purposes		22,840		21,290
Other Comprehensive Income		9,830		12,865
Total		35,261		36,200
Net Deferred Tax Liabilities	$	255,061	$	212,120

As of December 31, 2005, the Company had a net operating loss carryforward of $50.3 million for state income tax reporting purposes, the majority of which will expire between 2013 and 2025 and none available for regular federal income tax purposes. It is expected that these deferred tax benefits will be utilized prior to their expiration.

7. Commitments and Contingencies

Firm Gas Transportation Agreements and Drilling Rig Commitments

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 in Canada, the West and the East. The remaining terms on these agreements range from 2 to 22 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company.

Future obligations under firm gas transportation agreements in effect at December 31, 2005 are as follows:

(In thousands)
2006	$	11,661
2007		11,626
2008		8,213
2009		3,381
2010		3,381
Thereafter		55,504
	$	93,766

The Company also has three drilling rigs in the Gulf Coast under contract that are not yet delivered and two existing rigs in the Gulf Coast under contract through 2008. As of December 31, 2005, the Company is obligated over the next 4 years to pay $104.3 million as follows:

(In thousands)
2006	$	26,055
2007		41,245
2008		27,340
2009		9,675
	$	104,315

Subsequent to December 31, 2005, the Company entered into an agreement for one additional drilling rig in the Gulf Coast. The total commitment over the next four years is $27.4 million, of which $0.8 million, $9.1 million, $9.1 million and $8.4 million will be paid out during the years 2006, 2007, 2008 and 2009, respectively.

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Lease Commitments

The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. The lease for the Company’s office in Houston runs for approximately four more years. Most of the Company’s leases expire within five years and may be renewed. Rent expense under such arrangements totaled $9.1 million, $8.7 million, and $8.5 million for the years ended December 31, 2005, 2004, and 2003, respectively.

Future minimum rental commitments under non-cancelable leases in effect at December 31, 2005 are as follows:

(In thousands)
2006	$	4,876
2007		4,633
2008		4,541
2009		3,207
2010		489
Thereafter		—
	$	17,746

Contingencies

The Company is a defendant in various legal proceedings arising in the normal course of our business. All known liabilities are accrued based on management’s best estimate of the potential loss. 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 consolidated financial position or cash flow. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

Wyoming Royalty Litigation

In January 2002, 13 overriding royalty owners sued the Company in Wyoming federal district court, as reported in previous filings. The plaintiffs made claims pertaining to deductions from their overriding royalty and claims concerning penalties for improper reporting. As a result of several decisions by the Court favorable to the Company, the case was settled in September 2005 with no payment from the Company and a dismissal with prejudice of all claims by plaintiffs. The settlement included provisions for reporting and payment going forward. Management has reversed the reserve it had recorded regarding this case, which had an immaterial impact on the Company’s consolidated financial statements.

West Virginia Royalty Litigation

In December 2001, the Company was sued by two royalty owners in West Virginia state court for an unspecified amount of damages. The plaintiffs have requested class certification and allege that the Company failed to pay royalty based upon the wholesale market value of the gas, that it had taken improper deductions from the royalty and failed to properly inform royalty owners of the deductions. The plaintiffs also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that the Company reached with Columbia Gas Transmission Corporation in 1995 bankruptcy proceedings.

Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. The Court entered an order on June 1, 2005 granting the motion for class certification. The parties have negotiated a modification to the order which will result in the dismissal of the claims related to the gas sales contract settlement in connection with the Columbia Gas Transmission bankruptcy proceedings and that will limit the claims to those arising on and after December 17, 1991. The Court has postponed the trial date from April 17, 2006, in light of a case pending before the West Virginia Supreme Court of Appeals which may decide issues of law that may apply to the issue of deductibility of post-production expenses. The Company intends to challenge the class certification order by filing a Petition for Writ of Prohibition with the West Virginia Supreme Court of Appeals.

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The Company is vigorously defending the case. A reserve has been established that management believes is adequate based on its estimate of the probable outcome of this case.

Texas Title Litigation

On January 6, 2003, the Company was served with Plaintiffs’ Second Amended Original Petition in Romeo Longoria, et al. v. Exxon Mobil Corporation, et al. in the 79th Judicial District Court of Brooks County, Texas. Plaintiffs filed their Second Supplemental Original Petition on November 12, 2004 and their Third Supplemental Original Petition on February 22, 2005 (which added Wynn-Crosby 1996, Ltd. and Dominion Oklahoma Texas Exploration & Production, Inc.). Plaintiffs allege that they are the owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. Cody Energy, LLC, a subsidiary of the Company, acquired certain leases and wells in 1997 and 1998.

The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. Plaintiffs claim that they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a claim of fraudulent concealment to avoid the affirmative defense of limitations. In August 2005, the case was abated until late February 2006, during which time the parties are allowed to amend pleadings or add additional parties to the litigation. Due to the abatement of the case, the Company has not had the opportunity to conduct discovery in this matter. The Company estimates that production revenue from this field since Cody Energy, LLC acquired title is approximately $15.7 million, and that the carrying value of this property is approximately $33.6 million.

Although the investigation into this claim continues, the Company intends to vigorously defend the case. Should the Company receive an adverse ruling in this case, an impairment review would be assessed to determine whether the carrying value of the property is recoverable. Management cannot currently determine the likelihood of an unfavorable outcome or range of any potential loss should the outcome be unfavorable. Accordingly, there has been no reserve established for this matter.

Raymondville Area

In April 2004, the Company’s wholly owned subsidiary, Cody Energy, LLC, filed suit in state court in Willacy County, Texas against certain of its co-working interest owners in the Raymondville Area, located in Kenedy and Willacy Counties. In early 2003, Cody had proposed a new prospect under the terms of the Joint Operating Agreement. Some of the co-working interest owners elected not to participate. The initial well was successful and subsequent wells have been drilled to exploit the discovery made in the first well.

The working interest owners who elected not to participate notified Cody that they believed that they had the right to participate in wells drilled after the initial well. Cody contends that the working interest owners that elected not to participate are required to assign their interest in the prospect to those who elected to participate. The defendants have filed a counter claim against the Company, and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville area.

Cody has signed a settlement agreement with certain of the defendants representing approximately 3% of the interest in the area. Cody and the remaining defendant filed cross motions for summary judgment. In August 2005, the trial judge entered an order granting Cody’s Motion for Summary Judgment requiring the remaining defendant to assign to Cody all of its interest in the prospect and to remove the lien filed against Cody’s interest. The defendant has filed a Motion for Reconsideration and Opposition to Proposed Order. The Court has not yet made a decision on these two motions.

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Commitment and Contingency Reserves

The Company has established reserves for certain legal proceedings. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it is reasonably possible that the Company could incur approximately $10.2 million of additional loss with respect to those matters in which reserves have been established. Future changes in the facts and circumstances could result in the actual liability exceeding the estimated ranges of loss and amounts accrued.

While the outcome and impact 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 consolidated financial position or cash flow of the Company. Operating results, however, could be significantly impacted in the reporting periods in which such matters are resolved.

8. Cash Flow Information

Cash paid for interest and income taxes is as follows:

	Year Ended December 31,
(In thousands)	2005		2004		2003
Interest	$	17,366	$	16,415	$	18,298
Income Taxes		47,142		29,861		19,267

The Company recorded benefits of $3.7 million, $2.6 million and $1.0 million for the years ended December 31, 2005, 2004 and 2003, respectively, for tax deductions taken due to employee stock option exercises and restricted stock grant vesting.

9. Capital Stock

On February 28, 2005, the Company announced that the Board of Directors had declared a 3-for-2 split of the Company’s common stock in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the common stock on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s common stock.

Incentive Plans

On April 29, 2004, the 2004 Incentive Plan was approved by the shareholders. Under the 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 addition to the automatic award of an option to purchase 15,000 shares of common stock on the date the non-employee directors first join the board of directors. A total of 2,550,000 shares of common stock may be issued under the 2004 Incentive Plan. In addition, shares remaining available for award under the 1994 Long-Term Incentive Plan and the Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (herein “Prior Plans”) were subsumed into the 2004 Incentive Plan (342,597 shares post-split). Under the 2004 Incentive Plan, no more than 900,000 shares may be used for stock awards that are not subject to the achievement of performance based goals, and no more than 1,500,000 shares may be issued pursuant to incentive stock options. Awards outstanding under the Prior Plans will remain outstanding in accordance with their original terms and conditions.

During 2005, the Board of Directors granted a series of 110,200 performance share awards to the executives of the Company. These awards are 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 vesting period ending on

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April 30, 2008. Depending on the Company’s performance, employees may earn up to 100% of the award in common stock, and an additional 100% of the award in cash. The performance shares qualify for variable accounting, and accordingly, are recorded at their fair value with compensation expense recognized over the performance period.

During 2005, the Company granted 19,600 restricted stock units to the non-employee Directors of the Company. These units immediately vest and will be paid out whenever the Director ceases to be a Director of the Company. For all restricted stock units, the Company recognized compensation expense equal to the market value of the Company’s common stock on the grant date of the respective awards.

Information regarding stock options under the Company’s 2004 Incentive Plan and the Prior Plans is summarized below:

	December 31,
	2005	2004	2003
Shares Under Option at Beginning of Period	1,217,534	2,024,252	1,931,744
Granted	—	36,750	700,500
Exercised	300,493	793,775	518,079
Surrendered or Expired	3,693	49,693	89,913
Shares Under Option at End of Period	913,348	1,217,534	2,024,252
Options Exercisable at End of Period	895,848	565,994	767,579

For each of the three most recent years, the price range for outstanding options was $11.63 to $23.32 per share. The following tables provide more information about the options by exercise price and year.

Options with exercise prices between $11.63 and $15.00 per share:

	December 31,
	2005		2004		2003
Options Outstanding
Number of Options		225,575		344,945		667,002
Weighted Average Exercise Price	$	12.84	$	12.85	$	12.81
Weighted Average Contractual Term (in years)		1.1		2.0		2.6
Options Exercisable
Number of Options		225,575		183,737		306,344
Weighted Average Exercise Price	$	12.84	$	12.86	$	12.69

Options with exercise prices between $15.01 and $23.32 per share:

	December 31,
	2005		2004		2003
Options Outstanding
Number of Options		687,773		872,589		1,357,250
Weighted Average Exercise Price	$	16.14	$	16.16	$	16.46
Weighted Average Contractual Term (in years)		1.9		2.7		3.4
Options Exercisable
Number of Options		670,273		382,257		461,235
Weighted Average Exercise Price	$	16.13	$	16.29	$	17.61

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.

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Treasury Stock

In August 1998, the Board of Directors authorized the Company to repurchase up to two million shares of outstanding common stock at market prices. As a result of the 3-for-2 split of the Company’s common stock in March 2005, this figure has been adjusted to three million shares. 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. During the year ended December 31, 2005, the Company repurchased 452,300 shares for a total cost of approximately $19.2 million. The repurchased shares are held as treasury stock. Since the authorization date, the Company has repurchased 1,513,850 shares, or 50% of the total shares authorized for repurchase, for a total cost of approximately $39.2 million. In 2005, the stock repurchase plan was funded from cash flow from operations. No treasury shares have been delivered or sold by the Company subsequent to the repurchase.

Purchase Rights

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. Each right becomes exercisable when any person or group has acquired or made a tender or exchange offer for beneficial ownership of 15% or more of the Company’s outstanding common stock. Each right entitles the holder, other than the acquiring person or group, to purchase a fraction of a share of Series A Junior Participating Preferred Stock (Junior Preferred Stock). After a person or group acquires beneficial ownership of 15% of the common stock, each right entitles the holder to purchase common stock or other property having a market value (as defined in the plan) of twice the exercise price of the right. An exception to this triggering event applies in the case of a tender or exchange offer for all outstanding shares of common stock determined to be fair and in the best interests of the Company and its stockholders by a majority of the independent directors. Under certain circumstances, the Board of Directors may opt to exchange one share of common stock for each exercisable right. If there is a 15% holder and the Company is acquired in a merger or other business combination in which it is not the survivor, or 50% or more of the Company’s assets or earning power are sold or transferred, each right entitles the holder to purchase common stock of the acquiring company with a market value (as defined in the plan) equal to twice the exercise price of each right. At December 31, 2005 there were no shares of Junior Preferred Stock issued or outstanding.

The rights expire on January 21, 2010, and may be redeemed by the Company at any time before a person or group acquires beneficial ownership of 15% of the common stock.

The 3-for-2 split of the Company’s common stock was consummated in the form of a stock distribution. The stock dividend was distributed on March 31, 2005 to stockholders of record on March 18, 2005. In lieu of issuing fractional shares, the Company paid cash based on the closing price of the common stock on the record date. As a result of the stock split, each share of common stock continues to include one right under the Company’s Preferred Stock Purchase Rights Plan, and each right now provides for the purchase, upon the occurrence of the conditions set forth in the plan, of two-thirds of one one-hundredth of a share of preferred stock at a purchase price of approximately $36.67 per two-thirds of one one-hundredth of a share. The redemption price of each right is now two-thirds of a cent. All common stock accounts and per share data have been retroactively adjusted to give effect to the 3-for-2 split of the Company’s common stock.

10. 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. The Company uses available marketing data and valuation methodologies to estimate the fair value of debt. This disclosure is presented in accordance with SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” and does not impact the Company’s financial position, results of operations or cash flows.

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Long-Term Debt

	December 31, 2005				December 31, 2004
(In thousands)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Debt
7.19% Notes	$	60,000	$	62,938	$	80,000	$	87,770
7.26% Notes		75,000		81,713		75,000		85,849
7.36% Notes		75,000		83,990		75,000		87,111
7.46% Notes		20,000		23,083		20,000		23,804
Credit Facility		90,000		90,000		—		—
	$	320,000	$	341,724	$	250,000	$	284,534

The fair value of long-term debt is the estimated cost to acquire the debt, including a premium or discount for the difference between the issue rate and the year end market rate. The fair value of the 7.19% Notes, the 7.26% Notes, the 7.36% Notes and the 7.46% Notes is based on interest rates currently available to the Company. The credit facility approximates fair value because this instrument bears interest at rates based on current market rates.

Derivative Instruments and Hedging Activity

The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. Under the Company’s revolving credit agreement, the aggregate level of commodity hedging must not exceed 100% of the anticipated future equivalent production during the period covered by these cash flow hedges. At December 31, 2005, the Company had nine cash flow hedges open: eight natural gas price collar arrangements and one crude oil collar arrangement. At December 31, 2005, a $20.7 million ($12.9 million net of tax) unrealized loss was recorded to Accumulated Other Comprehensive Income, along with a $22.4 million short-term derivative liability and a $1.7 million short-term derivative receivable, which is shown in Other Current Assets on the Balance Sheet. The change in the fair value of derivatives designated as hedges that is effective is initially recorded to Accumulated Other Comprehensive Income. The ineffective portion, if any, of the change in the fair value of derivatives designated as hedges, and the change in fair value of all other derivatives is recorded currently in earnings as a component of Natural Gas Production and Crude Oil and Condensate Revenue, as appropriate.

Assuming no change in commodity prices, after December 31, 2005 the Company would expect to reclassify to the Statement of Operations, over the next 12 months, $12.9 million in after-tax charges associated with commodity hedges. This reclassification represents the net liability associated with open positions currently not reflected in earnings at December 31, 2005 related to anticipated 2006 production.

Hedges on Production - Swaps

From time to time, the Company enters into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of its production. These derivatives are not held for trading purposes. Under these price swaps, the Company receives a fixed price on a notional quantity of natural gas and 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 2005, natural gas price swaps covered 20,557 Mmcf, or 28% of the Company’s gas production, fixing the sales price of this gas at an average of $5.14 per Mcf.

At December 31, 2005, the Company had no open natural gas price swap contracts covering 2006 production.

From time to time, the Company enters into natural gas and crude oil derivative arrangements that do not qualify for hedge accounting under SFAS No. 133. These financial instruments are recorded at fair value at the balance sheet date. At December 31, 2005, the Company did not have any of these types of arrangements.

Hedges on Production - Options

From time to time, the Company enters into natural gas and crude oil collar agreements with counterparties to hedge price risk associated with a portion of its production. These cash flow hedges are not held for trading purposes. Under the collar arrangements, if the index price rises above the ceiling price, the Company pays the counterparty. If the index price falls below

86

the floor price, the counterparty pays the Company. During 2005, natural gas price collars covered 15,157 Mmcf of the Company’s gas production, or 21% of gas production with a weighted average floor of $5.59 per Mcf and a weighted average ceiling of $8.61 per Mcf. During 2005, an oil price collar covered 365 Mbbl of the Company’s crude oil production, or 21% of crude oil production with a weighted average floor of $40.00 per Mbbl and a weighted average ceiling of $50.50 per Mbbl.

At December 31, 2005, the Company had open natural gas price collar contracts covering its 2006 production as follows:

	Natural Gas Price Collars
Contract Period	Volume in Mmcf	Weighted Average Ceiling / Floor		Net Unrealized Loss (In thousands)
As of December 31, 2005
First Quarter 2006	6,702	$	12.74 /$8.25
Second Quarter 2006	6,776		12.74 / 8.25
Third Quarter 2006	6,850		12.74 / 8.25
Fourth Quarter 2006	6,851		12.74 / 8.25
Full Year 2006	27,179	$	12.74 /$8.25	$	(20,425	)

At December 31, 2005, the Company had one open crude oil price collar contract covering its 2006 production as follows:

	Crude Oil Price Collar
Contract Period	Volume in Mbbl	Weighted Average Ceiling /Floor		Net Unrealized Loss (In thousands)
As of December 31, 2005
First Quarter 2006	90	$	76.00 /$50.00
Second Quarter 2006	91		76.00 / 50.00
Third Quarter 2006	92		76.00 / 50.00
Fourth Quarter 2006	92		76.00 / 50.00
Full Year 2006	365	$	76.00 /$50.00	$	(317	)

The Company is exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and crude oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.

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 each of 2005, 2004 and 2003, approximately 11% of the Company’s total sales were made to one customer

11. Adoption of SFAS 143, “Accounting for Asset Retirement Obligations”

Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized 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 assets useful life. The adoption of SFAS No. 143 resulted in an increase of total liabilities because additional retirement obligations are required to be recognized, an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived

87

asset and an increase in operating expense because of the accretion of the retirement obligation and additional depreciation and depletion. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. However, liabilities will also be recorded for meter stations, pipelines, processing plants and compressors. At December 31, 2005 there are no assets legally restricted for purposes of settling asset retirement obligations. The Company recorded a net-of-tax charge for the cumulative effect of change in accounting principle, in January of 2003, of approximately $6.8 million ($11.0 million before tax) and recorded a retirement obligation of approximately $35.2 million. There was no impact on the Company’s cash flows as a result of adopting SFAS No. 143.

Additional retirement obligations increase the liability associated with new oil and gas wells and other facilities as these obligations are incurred. Accretion expense for the years ended December 31, 2005, 2004 and 2003 was $1.4 million, $1.7 million and $2.1 million, respectively.

The following table reflects the changes of the asset retirement obligations during the current period.

(In thousands)
Carrying amount of asset retirement obligations at December 31, 2004	$	40,375
Liabilities added during the current period		1,364
Liabilities settled during the current period		(110	)
Current period accretion expense		1,419
Revisions to estimated cash flows		(57	)
Carrying amount of asset retirement obligations at December 31, 2005	$	42,991

12. Earnings per Common Share

Basic earnings per common share (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 using the treasury stock method except that the denominator is increased to reflect the potential dilution that could occur if outstanding stock options and stock awards outstanding at the end of the applicable period were exercised for common stock.

The following is a calculation of basic and diluted weighted average shares outstanding for the year ended December 31, 2005, 2004 and 2003:

	December 31,
	2005	2004	2003
Shares - basic	48,856,491	48,732,504	48,074,496
Dilution effect of stock options and awards at end of period	868,904	606,297	360,932
Shares - diluted	49,725,395	49,338,801	48,435,428
Stock awards and shares excluded from diluted earnings per share due to the anti-dilutive effect	—	—	1,448,666

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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.

Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made.

Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

Estimates of proved and proved developed reserves at December 31, 2005, 2004, and 2003 were based on studies performed by the Company’s petroleum engineering staff. The estimates were computed based on year end prices for oil, natural gas, and natural gas liquids. The estimates were reviewed by Miller and Lents, Ltd., who indicated in their letter dated February 3, 2006, that based on their investigation and subject to the limitations described in their 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, 2005, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.

The following table illustrates the Company’s net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by the Company’s engineering staff.

	Natural Gas
	December 31,
(Millions of cubic feet)	2005		2004		2003
Proved Reserves
Beginning of Year	1,134,081		1,069,484		1,060,959
Revisions of Prior Estimates	(1,543	)	(7,850	)	(6,122	)
Extensions, Discoveries and Other Additions	185,884		140,986		105,497
Production	(73,879	)	(72,833	)	(71,906	)
Purchases of Reserves in Place	17,567		5,384		1,590
Sales of Reserves in Place	(14	)	(1,090	)	(20,534	)
End of Year	1,262,096		1,134,081		1,069,484
Proved Developed Reserves	944,897		857,834		812,280
Percentage of Reserves Developed	74.9	%	75.6	%	76.0	%

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	Liquids
	December 31,
(Thousands of barrels)	2005		2004		2003
Proved Reserves
Beginning of Year	11,384		12,103		18,393
Revisions of Prior Estimates	1,073		185		307
Extensions, Discoveries and Other Additions	334		1,074		1,723
Production	(1,747	)	(2,002	)	(2,846	)
Purchases of Reserves in Place	419		24		—
Sales of Reserves in Place	—		—		(5,474	)
End of Year	11,463		11,384		12,103
Proved Developed Reserves	9,127		8,652		9,405
Percentage of Reserves Developed	79.6	%	76.0	%	77.7	%

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)	2005		2004		2003
Aggregate Capitalized Costs Relating to Oil and Gas Producing Activities	$	2,290,147	$	1,933,848	$	1,732,236
Aggregate Accumulated Depreciation, Depletion and Amortization		1,052,654		940,447		837,060

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)	2005		2004		2003
Property Acquisition Costs, Proved	$	73,127	$	3,953	$	1,524
Property Acquisition Costs, Unproved		22,126		18,250		14,056
Exploration and Extension Well Costs (1)		102,957		85,415		83,147
Development Costs		208,124		136,311		77,006
Total Costs	$	406,334	$	243,929	$	175,733

⁽¹⁾ Includes administrative exploration costs of $12,423, $11,354 and $10,582 for the years ended December 31, 2005,

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Historical Results of Operations from Oil and Gas Producing Activities

The results of operations for the Company’s oil and gas producing activities were as follows:

	Year Ended December 31,
(In thousands)	2005		2004		2003
Operating Revenues	$	581,849	$	439,988	$	404,503
Costs and Expenses
Production		103,477		84,015		77,315
Other Operating		30,120		27,787		20,090
Exploration (1)		61,840		48,130		58,119
Depreciation, Depletion and Amortization		119,122		114,906		195,659
Total Costs and Expenses		314,559		274,838		351,183
Income Before Income Taxes		267,290		165,150		53,320
Provision for Income Taxes		100,353		60,361		18,662
Results of Operations	$	166,937	$	104,789	$	34,658

⁽¹⁾ Includes administrative exploration costs of $12,423, $11,354 and $10,582 for the years ended December 31, 2005, 2004, and 2003, respectively.

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

The following information has been developed utilizing SFAS No. 69, “Disclosures about Oil and Gas Producing Activities”, procedures 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 were estimated by applying year end oil and gas prices to the estimated future production of year end proved reserves.

The average prices related to proved reserves at December 31, 2005, 2004, and 2003 for natural gas ($ per Mcf) were $9.53, $6.26 and $5.96, respectively, and for oil ($ per Bbl) were $58.48, $41.24 and $30.94, 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. SFAS No. 69 requires the use of a 10% discount rate.

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

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Standardized Measure is as follows:

	Year Ended December 31,
(In thousands)	2005			2004			2003
Future Cash Inflows	$	12,700,390		$	7,561,728		$	6,742,214
Future Production Costs		(2,271,917	)		(1,577,787	)		(1,390,398	)
Future Development Costs		(536,333	)		(396,431	)		(310,923	)
Future Income Tax Expenses		(3,588,877	)		(2,009,644	)		(1,800,519	)
Future Net Cash Flows		6,303,263			3,577,866			3,240,374
10% Annual Discount for Estimated Timing of Cash Flows		(3,652,030	)		(1,997,509	)		(1,760,966	)
Standardized Measure of Discounted Future Net Cash Flows (1)	$	2,651,233		$	1,580,357		$	1,479,408

⁽¹⁾ The standardized measures of discounted future net cash flows before taxes were $4,001,769, $2,358,430 and $2,196,038 for the years ended December 31, 2005, 2004 and 2003, respectively.

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)	2005			2004			2003
Beginning of Year	$	1,580,357		$	1,479,408		$	1,255,353
Discoveries and Extensions, Net of Related Future Costs		494,773			321,026			235,079
Net Changes in Prices and Production Costs		1,278,303			(17,976	)		475,026
Accretion of Discount		235,843			219,604			171,590
Revisions of Previous Quantity Estimates, Timing and Other		(49,550	)		(46,115	)		(35,691	)
Development Costs Incurred		61,802			32,940			27,529
Sales and Transfers, Net of Production Costs		(471,638	)		(357,939	)		(330,800	)
Net Purchases (Sales) of Reserves in Place		91,180			10,853			(62,596	)
Net Change in Income Taxes		(569,837	)		(61,444	)		(256,082	)
End of Year	$	2,651,233		$	1,580,357		$	1,479,408

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CABOT OIL & GAS CORPORATION

SELECTED DATA (UNAUDITED)

QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

(In thousands, except per share amounts)	First		Second		Third		Fourth		Total
2005
Operating Revenues	$	144,074	$	151,884	$	161,757	$	225,082	$	682,797
Impairment of Oil and Gas Properties (1)		—		—		—		—		—
Operating Income		38,044		61,722		59,023		99,942		258,731
Net Income		20,762		35,422		33,756		58,505		148,445
Basic Earnings per Share (2)		0.43		0.72		0.69		1.20		3.04
Diluted Earnings per Share (2)		0.42		0.71		0.68		1.18		2.99
2004
Operating Revenues	$	136,604	$	119,742	$	119,423	$	154,639	$	530,408
Impairment of Oil and Gas Properties (1)		—		—		3,458		—		3,458
Operating Income		36,090		36,439		34,278		53,846		160,653
Net Income		19,011		19,318		17,822		32,227		88,378
Basic Earnings per Share (2)		0.39		0.40		0.37		0.66		1.81
Diluted Earnings per Share (2)		0.39		0.39		0.36		0.65		1.79

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

⁽²⁾ All Earnings per Share figures have been retroactively adjusted for the 3-for-2 split of the Company’s Common Stock effective March 31, 2005.

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

None.

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ITEM 9A. CONTROLS AND PROCEDURES

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

As of the end of December 31, 2005, 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 issuer in the reports that it files or submits under the Exchange Act.

There were no significant 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, 2005. 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, 2005, the Company’s internal control over financial reporting is effective based on those criteria.

Cabot Oil & Gas Corporation’s independent registered public accounting firm has audited management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 as stated in their report entitled “Report of Independent Registered Public Accounting Firm” which appears herein.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information under the captions “Election of Directors”, “Audit Committee” and “Code of Business Conduct” in the Company’s definitive Proxy Statement in connection with the 2006 annual stockholders’ meeting are incorporated by reference. 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.

94

ITEM 11. EXECUTIVE COMPENSATION

The information under the caption “Executive Compensation” in the Company’s definitive Proxy Statement in connection with the 2006 annual stockholders’ meeting is incorporated by reference.

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

The information under the captions “Beneficial Ownership of Over Five Percent of Common Stock”, “Beneficial Ownership of Directors and Executive Officers”, and “Equity Compensation Plan Information” in the Company’s definitive Proxy Statement in connection with the 2006 annual stockholders’ meeting are incorporated by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information under the caption “Fees Billed by Independent Public Accountants for Services in 2005 and 2004” in the Company’s definitive Proxy Statement in connection with the 2006 annual stockholders’ meeting is incorporated by reference.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

A. INDEX

1. Consolidated Financial Statements

See Index on page 53.

2. Financial Statement Schedules

None.

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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.

Exhibit Number	Description
3.1	Certificate of Incorporation of the Company (Registration Statement No. 33-32553).
3.2	Amended and Restated Bylaws of the Company amended September 6, 2001 (Form 10-K for 2001).
3.3	Certificate of Amendment of Certificate of Incorporation (Form 8-K for July 2, 2002).
3.4	Certificate of Increase of Shares Designated Series A Junior Participating Preferred Stock (Form 8-K for July 2, 2002).
4.1	Form of Certificate of Common Stock of the Company (Registration Statement No. 33-32553).
4.2	Certificate of Designation for Series A Junior Participating Preferred Stock (Form 10-K for 1994).
4.3	Rights Agreement dated as of March 28, 1991, between the Company and The First National Bank of Boston, as Rights Agent, which includes as Exhibit A the form of Certificate of Designation of Series A Junior Participating Preferred Stock (Form 8-A, File No. 1-10477).
	(a)	Amendment No. 1 to the Rights Agreement dated February 24, 1994 (Form 10-K for 1994).
	(b)	Amendment No. 2 to the Rights Agreement dated December 8, 2000 (Form 8-K for December 21, 2000).
4.4	Certificate of Designation for 6% Convertible Redeemable Preferred Stock (Form 10-K for 1994).
4.5	Amended and Restated Credit Agreement dated as of May 30, 1995, among the Company, Morgan Guaranty Trust Company, as agent and the banks named therein (Form 10-K for 1995).
	(a)	Amendment No. 1 to Credit Agreement dated September 15, 1995 (Form 10-K for 1995).
	(b)	Amendment No. 2 to Credit Agreement dated December 24, 1996 (Form 10-K for 1996).
4.6	Note Purchase Agreement dated November 14, 1997, among the Company and the purchasers named therein (Form 10-K for 1997).
4.7	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).
4.8	Credit Agreement dated as of October 28, 2002 among the Company, the Banks Parties Hereto and Fleet National Bank, as administrative agent (Form 10-Q for the quarter ended September 30, 2002).
	(a)	Amendment No. 1 to Credit Agreement dated December 10, 2004 (Form 10-K for 2004).
*10.1	Form of Change in Control Agreement between the Company and Certain Officers (Form 10-K for 2001).
*10.2	Form of Annual Target Cash Incentive Plan of the Company (Registration Statement No. 33-32553).
*10.3	Form of Incentive Stock Option Plan of the Company (Registration Statement No. 33-32553).
	(a)	First Amendment to the Incentive Stock Option Plan (Post-Effective Amendment No. 1 to S-8 dated April 26, 1993).

96

Exhibit Number	Description
*10.4	Savings Investment Plan & Trust Agreement of the Company (Form 10-K for 1991).
	(a)	First Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993).
	(b)	Second Amendment to the Savings Investment Plan dated May 21, 1993 (Form S-8 dated November 1, 1993).
	(c)	First through Fifth Amendments to the Trust Agreement (Form 10-K for 1995).
	(d)	Third through Fifth Amendments to the Savings Investment Plan (Form 10-K for 1996).
*10.5	Supplemental Executive Retirement Agreements of the Company (Form 10-K for 1991).
*10.6	1990 Non-employee Director Stock Option Plan of the Company (Form S-8 dated June 23, 1990).
	(a)	First Amendment to 1990 Non-employee Director Stock Option Plan (Post-Effective Amendment No. 2 to Form S-8 dated March 7, 1994).
	(b)	Second Amendment to 1990 Non-employee Director Stock Option Plan (Form 10-K for 1995).
*10.7	Second Amended and Restated 1994 Long-Term Incentive Plan of the Company (Form 10-K for 2001).
*10.8	Second Amended and Restated 1994 Non-Employee Director Stock Option Plan (Form 10-K for 2001).
*10.9	Form of Indemnity Agreement between the Company and Certain Officers (Form 10-K for 1997).
*10.10	Deferred Compensation Plan of the Company as Amended September 1, 2001 (Form 10-K for 2001).
10.11	Trust Agreement dated September 2000 between Harris Trust and Savings Bank and the Company (Form 10-K for 2001).
10.12	Lease Agreement between the Company and DNA COG, Ltd. dated April 24, 1998 (Form 10-K for 1998).
10.13	Credit Agreement dated as of December 17, 1998, between the Company and the banks named therein (Form 10-K for 1998).
*10.14	Employment Agreement between the Company and Dan O. Dinges dated August 29, 2001 (Form 10-K for 2001).
*10.15	2004 Incentive Plan (Form 10-Q for the quarter ended June 30, 2004).
*10.16	2004 Performance Award Agreement (Form 10-Q for the quarter ended June 30, 2004).
*10.17	2004 Annual Target Cash Incentive Plan Measurement Criteria for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).
*10.18	Form of Restricted Stock Awards Terms and Conditions for Cabot Oil & Gas Corporation (Form 8-K for February 10, 2005).
*10.19	2005 Form of Non-Employee Director Restricted Stock Unit Award Agreement (Form 8-K for May 24, 2005).
*10.20	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).
14.1	Amendment of Code of Business Conduct (as amended on July 28, 2005 to revise Section III. F. relating to Transactions in Securities and Article V. relating to Safety, Health and the Environment) (Form 10-Q for the quarter ended June 30, 2005).
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.

97

Exhibit Number	Description
31.2	302 Certification – Vice President and Chief Financial Officer.
32.1	906 Certification.
99.1	Miller and Lents, Ltd. Review Letter.

^* Compensatory plan, contract or arrangement.

98

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 6th of March 2006.

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

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

Signature	Title	Date
/s/ Dan O. Dinges Dan O. Dinges	Chairman, President and Chief Executive Officer (Principal Executive Officer)	March 6, 2006
/s/ Scott C. Schroeder Scott C. Schroeder	Vice President and Chief Financial Officer (Principal Financial Officer)	March 6, 2006
/s/ Henry C. Smyth Henry C. Smyth	Vice President, Controller and Treasurer (Principal Accounting Officer)	March 6, 2006
/s/ Robert F. Bailey Robert F. Bailey	Director	March 6, 2006
/s/ John G. L. Cabot John G. L. Cabot	Director	March 6, 2006
/s/ David M. Carmichael David M. Carmichael	Director	March 6, 2006
/s/ James G. Floyd James G. Floyd	Director	March 6, 2006
/s/ Robert L. Keiser Robert L. Keiser	Director	March 6, 2006
/s/ Robert Kelley Robert Kelley	Director	March 6, 2006
/s/ C. Wayne Nance C. Wayne Nance	Director	March 6, 2006
/s/ P. Dexter Peacock P. Dexter Peacock	Director	March 6, 2006
/s/ William P. Vititoe William P. Vititoe	Director	March 6, 2006

99

EX-10.20

Exhibit 10.20

CABOT OIL & GAS CORPORATION

SAVINGS INVESTMENT PLAN

(As Amended and Restated Effective January 1, 2001)

I N D E X

		Page
ARTICLE I DEFINITIONS		2
1.1	Account	2
1.2	Affiliate	2
1.3	After-Tax Contribution Account	2
1.4	After-Tax Contributions	2
1.5	Authorized Leave of Absence	2
1.6	Beneficiary	2
1.7	Board of Directors	2
1.8	Code	2
1.9	Committee	2
1.10	Company	2
1.11	Compensation	2
1.12	Contribution	3
1.13	ERISA	3
1.14	Effective Date	3
1.15	Employee	3
1.16	Employer	3
1.17	Employer Contribution Account	4
1.18	Employment Year	4
1.19	Entry Date	4
1.20	ESOP	4
1.21	ESOP Account	4
1.22	Forfeiture	4
1.23	Hour(s) of Service	4
1.24	Income of the Trust Fund	5
1.25	Investment Fund(s)	5
1.26	Leased Employee	5
1.27	Member	5
1.28	Plan	5
1.29	Plan Quarter	5
1.30	Plan Year	5
1.31	Pre-Tax Contribution Account	5
1.32	Prior Plan	6
1.33	Profit Sharing Plan	6
1.34	Profit Sharing Plan Account	6

i

1.35	Retirement Date	6
1.36	Rollover Account	6
1.37	Rollover Amount	6
1.38	Service	6
1.39	Total and Permanent Disability	6
1.40	Trust	6
1.41	Trust Agreement	7
1.42	Trust Fund	7
1.43	Trustee	7
1.44	Valuation Date	7
1.45	Vesting Service	7
1.46	Year of Service	7
ARTICLE II ADMINISTRATION OF THE PLAN		8
2.1	Allocation of Responsibility Among Fiduciaries for Plan and Trust Administration	8
2.2	Appointment of Committee	8
2.3	Records and Reports	8
2.4	Other Committee Powers and Duties	9
2.5	Rules and Decisions	9
2.6	Committee Procedure	10
2.7	Authorization of Benefit Payments	10
2.8	Payment of Expenses	10
2.9	Application and Forms for Benefits	10
2.10	Committee Liability	10
2.11	Statements	11
2.12	Annual Audit	11
2.13	Funding Policy	11
2.14	Allocation and Delegation of Committee Responsibilities	12
2.15	Presenting Claims for Benefits	12
2.16	Claims Review Procedure	12
ARTICLE III PARTICIPATION AND SERVICE		13
3.1	Eligibility for Participation	13
3.2	Notification of Eligible Employees	13
3.3	Applications by Employees	13
3.4	Authorized Absences	13
3.5	Break In Service	14
3.6	Participation and Vesting Service Upon Re-employment Before a Break In Service	14
3.7	Participation and Vesting Service Upon Re-employment After a Break In Service	14
3.8	Vesting Service	15
3.9	Transferred Members	15
3.10	Special Eligibility and Vesting for Certain Employees	16
3.11	Automatic Vesting Service	16
3.12	Qualified Military Service	16

ii

ARTICLE IV CONTRIBUTIONS AND FORFEITURES		17
4.1	Savings Contributions	17
4.2	Employer Contributions	18
4.3	Employer Contributions and Pre-Tax Contributions to be Tax Deductible	19
4.4	Suspension of Contributions	19
4.5	Delivery to Trustee	19
4.6	Application of Funds	19
4.7	Rollover Amounts	19
4.8	Disposition of Forfeitures	19
4.9	Contributions Generally Irrevocable	20
ARTICLE V MEMBER ACCOUNTS		21
5.1	Individual Accounts	21
5.2	Account Adjustments	21
5.3	Recognition of Different Investment Funds	22
5.4	Valuation of Trust Fund	22
ARTICLE VI WITHDRAWALS AND LOANS		23
6.1	Withdrawals from Profit Sharing Plan Account	23
6.2	Withdrawals of Amounts From After-Tax Contribution Account	25
6.3	Withdrawals of Amounts From Pre-Tax Account	25
6.4	Withdrawals from Employer Contribution, ESOP and Rollover Accounts	25
6.5	Loans to Members	25
ARTICLE VII MEMBERS’ BENEFITS		27
7.1	Retirement of Members on or after Retirement Date	27
7.2	Disability of Members	27
7.3	Death of Members	27
7.4	Other Termination of Service	27
7.5	Valuation Dates Determinative of Member’s Rights	28
7.6	Vesting for Certain Employees	28
ARTICLE VIII PAYMENT OF BENEFITS		29
8.1	Payment of Benefits	29
8.2	Distribution Upon Death	30
8.3	Required Minimum Distributions	31
8.4	Disputed Benefits	31
8.5	Member’s Right to Transfer Eligible Rollover Distribution	31
ARTICLE IX TRUST AGREEMENT; INVESTMENT FUNDS; INVESTMENT DIRECTIONS		33
9.1	Trust Agreement	33
9.2	Investment Funds	33
9.3	Investment Directions of Members	33

iii

9.4	Change of Investment Directions	33
9.5	Benefits Paid Solely from Trust Fund	34
9.6	Committee Directions to Trustee	34
9.7	Authority to Designate Investment Manager	34
9.8	Liquidation of Cabot MicroElectronics Stock	34
ARTICLE X ADOPTION OF PLAN BY OTHER ORGANIZATIONS; SEPARATION OF THE TRUST FUND; AMENDMENT AND TERMINATION OF THE PLAN; DISCONTINUANCE OF CONTRIBUTIONS TO THE TRUST FUND		35
10.1	Adoptive Instrument	35
10.2	Separation of the Trust Fund	35
10.3	Voluntary Separation	35
10.4	Amendment of the Plan	36
10.5	Acceptance or Rejection of Amendment by Employers	36
10.6	Termination of the Plan	36
10.7	Liquidation and Distribution of Trust Fund Upon Termination	37
10.8	Effect of Termination or Discontinuance of Contributions	37
10.9	Merger of Plan with Another Plan	37
10.10	Consolidation or Merger with Another Employer	38
ARTICLE XI MISCELLANEOUS PROVISIONS		39
11.1	Terms of Employment	39
11.2	Controlling Law	39
11.3	Invalidity of Particular Provisions	39
11.4	Non-Alienation of Benefits	39
11.5	Payments in Satisfaction of Claims of Members	39
11.6	Payments Due Minors and Incompetents	40
11.7	Impossibility of Diversion of Trust Fund	40
11.8	Evidence Furnished Conclusive	40
11.9	Copy Available to Members	40
11.10	Unclaimed Benefits	40
11.11	Headings for Convenience Only	40
11.12	Successors and Assigns	40
ARTICLE XII LIMITATION ON BENEFITS		41
I.	Single Defined Contribution Plan	41
II.	Two or More Defined Contribution Plans	42
ARTICLE XIII TOP-HEAVY PLAN REQUIREMENTS		45
13.1	General Rule	45
13.2	Vesting Provisions	45
13.3	Minimum Contribution Provisions	45
13.4	Limitation on Compensation	46
13.5	Coordination with Other Plans	46
13.6	Distributions to Certain Key Employees	46
13.7	Determination of Top-Heavy Status	46

iv

ARTICLE XIV TESTING OF CONTRIBUTIONS		51
14.1	Definitions	51
14.2	Actual Deferral Percentage	52
14.3	Actual Deferral Percentage Limits	52
14.4	Reduction of Pre-Tax Contribution Rates by Leveling Method	52
14.5	Increase in Pre-Tax Contribution Rates	53
14.6	Excess Pre-Tax Contributions	53
14.7	Contribution Percentage	54
14.8	Contribution Percentage Limits	54
14.9	Treatment of Excess Aggregate Contributions	55
14.10	Application of Participation and Discrimination Standards	56

v

CABOT OIL & GAS CORPORATION SAVINGS INVESTMENT PLAN

(As Amended and Restated Effective January 1, 2001)

Recitals

Cabot Oil and Gas Corporation, a Delaware corporation (the “Company”), adopted the Cabot Corporation Profit Sharing and Savings Plan and its related trust for the benefit of its eligible employees and the eligible employees of certain of its subsidiaries who might adopt said Plan, effective October 1, 1976 (the “1976 Plan”).

Effective January 1, 1991, the Board of Directors of the Company authorized the establishment of the Cabot Oil and Gas Corporation Savings Investment Plan (the “Prior Plan”) to replace the 1976 Plan, and each Company employee’s accounts in the 1976 Plan and the Cabot Corporation Employee Stock Ownership Plan were transferred to the Prior Plan at such time. The Prior Plan was subsequently amended by the First through Eleventh Amendments thereto.

Effective January 1, 2001, the Board of Directors of the Company authorized the amendment and restatement of the Prior Plan in the form set forth herein (the “Plan”) to incorporate the prior amendments, to incorporate changes required by certain legislative acts, and to make certain other changes. There shall be no termination and no gap or lapse in time or effect between the Prior Plan as in effect on December 31, 2000, and this Plan.

The Plan and the Trust, which is intended to form a part of the Plan, are intended to meet the requirements of Sections 401(a), 401(k) and 501(a) of the Internal Revenue Code of 1986, and the Employee Retirement Income Security Act of 1974, as either may be amended from time to time.

The provisions of this Plan shall apply to a Member who terminates Service on or after January 1, 2001. The rights and benefits, if any, of a former employee shall be determined in accordance with the provisions of the Prior Plan in effect on the date his employment terminated.

NOW, THEREFORE, Cabot Oil and Gas Corporation hereby amends, restates in its entirety, and continues the Cabot Oil & Gas Corporation Savings Investment Plan, effective January 1, 2001, a profit-sharing plan within the meaning of Code Section 401(a)(27), as follows:

1

ARTICLE I

DEFINITIONS

As used in this Plan, the following words and phrases shall have the following meanings unless the context clearly requires a different meaning:

1.1 Account: Collectively, the accounts maintained for each Member pursuant to Section 5.1, and shall include accounts provided for in the Profit Sharing Plan.

1.2 Affiliate: A corporation or other trade or business that is not an Employer under this Plan but which together with the Company is “under common control” within the meaning of Section 414(b) or (c), as modified by Section 415(h) of the Code; any organization (whether or not incorporated) which, together with the Company, is a member of an “affiliated service group” within the meaning of Section 414(m) of the Code; and any other entity required to be aggregated with the Company pursuant to regulations under Section 414(o) of the Code.

1.3 After-Tax Contribution Account: The separate account maintained for a Member to record his After-Tax Contributions to the Plan and adjustments relating thereto.

1.4 After-Tax Contributions: The amount contributed by a Member pursuant to Section 4.1B.

1.5 Authorized Leave of Absence: Any absence authorized by the Employer or Affiliate under the Employer’s or Affiliate’s standard personnel practices provided that all persons under similar circumstances must be treated alike in the granting of such Authorized Leaves of Absence and provided further that the Member returns within the period of authorized absence.

1.6 Beneficiary: A Member’s spouse, or such other natural person or persons, or the trustee of an inter vivos trust for the benefit of natural persons, entitled to benefits hereunder following a Member’s death.

1.7 Board of Directors: The Board of Directors of the Company.

1.8 Code: The Internal Revenue Code of 1986, as now in effect or hereafter amended.

1.9 Committee: The Administrative Committee appointed by the Company to act as administrator of the Plan and to perform the duties described in Article II.

1.10 Company: Cabot Oil and Gas Corporation, a Delaware corporation, its predecessors and successors.

1.11 Compensation: The total non-deferred remuneration actually paid to a Member by the Employer for personal services rendered as an Employee, as reported on the Member’s Federal Income Tax Withholding Statement (Form W-2 or its subsequent equivalent) during the

2

applicable Plan Year and any amounts by which a Member’s normal remuneration is reduced pursuant to a voluntary salary reduction plan qualified under Section 125 of the Code, a qualified transportation fringe under Section 132(f) of the Code or a cash-or-deferred plan qualified under Section 401(k) of the Code, including salary, wages, overtime payments, and annual, discretionary and sign-on bonuses, but excluding any amounts contributed by or on behalf of an Employer to this Plan or any other employee benefit plan sponsored by the Company, non-deductible moving expenses, disability pay (both short-term and long-term), any income arising from the exercise of a stock option or from the receipt of a restricted stock award, reimbursements, expense allowances, severance pay (whether periodic or in a lump sum), taxable fringe benefits, waiver benefits, deductible payments under Section 105(h) of the Code, taxable group-term life insurance benefits, and retention and relocation bonuses. The Compensation of a Member as reflected on the books and records of the Employer shall be conclusive.

Notwithstanding anything herein to the contrary, in no event shall the Compensation taken into account under the Plan for any Employee exceed $170,000 or such other dollar amount as may be prescribed by the Commissioner for increases in the cost of living in accordance with Section 401(a)(17)(B) of the Code. 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.

1.12 Contribution: Any amount contributed to the Trust Fund pursuant to the provisions of this Plan, by an Employer or by a Member out of his Compensation. Contributions by the Employer shall sometimes be referred to as “Employer Contributions” and “Pre-Tax Contributions,” as specified under Sections 4.1 and 4.2 hereof.

1.13 ERISA: Public Law No. 93-406, the Employee Retirement Income Security Act of 1974, as amended from time to time.

1.14 Effective Date: January 1, 1991, the date as of which the provisions of the Prior Plan first became effective.

1.15 Employee: Any person who, on or after the Effective Date, is receiving remuneration for personal services (or would be receiving such remuneration except for an authorized leave of absence) as an employee of an Employer or who is a Leased Employee.

1.16 Employer: The Company, its successors, and any eligible organization which shall adopt this Plan pursuant to the provisions of Article X, and the successors, if any, to such organization.

3

1.17 Employer Contribution Account: The account maintained for a Member to record his share of the Contributions of his Employer and adjustments relating thereto.

1.18 Employment Year: The twelve consecutive month period determined from the Employee’s first performance of an Hour of Service and subsequent twelve-month periods beginning on the first anniversary of such Employee’s performance of such Hour of Service; provided, however, that in the case of any Employee who incurs a Break In Service, upon such Employee’s re-employment his Employment Year shall be deemed to commence on the date he first performs an Hour of Service after such Break In Service.

1.19 Entry Date: The first day of each calendar month and any such other date as determined by the Committee, communicated to the Employees and applied in a uniform and non-discriminatory manner thereafter.

1.20 ESOP: The Cabot Corporation Employee Stock Ownership Plan, as effective December 31, 1990.

1.21 ESOP Account: The account maintained for a Member who participated in the ESOP to record his contributions transferred from the ESOP to this Plan and adjustments relating thereto. Effective October 16, 2000, a Member shall be eligible to transfer the assets held in the Member’s ESOP Account to other Investment Funds provided under the Plan or to borrow assets from such account as provided under Section 6.5 of the Plan.

1.22 Forfeiture: The portion of a Member’s Employer Contribution Account which is forfeited because of termination of Service before full vesting pursuant to Section 7.4 and which occurs on the earlier of (a) the distribution of the entire vested portion of the Member’s Account or (b) the last day of the Plan Year in which the Member incurs five (5) consecutive one-year Breaks In Service.

1.23 Hour(s) of Service: 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 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

4

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. However, 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 a member of or after its cessation of membership in the Company’s affiliated service group, controlled group, or group of trades or businesses. Hours of Service will be credited for any individual considered an employee under Code Section 414(n).

1.24 Income of the Trust Fund: The net gain or loss of the Trust Fund from investments, as reflected by interest payments, dividends, realized and unrealized gains and losses on securities and other investment transactions and expenses paid from the Trust Fund.

1.25 Investment Fund(s): Any of the investment funds comprising the Trust Fund, as described in Section 9.2.

1.26 Leased Employee: Each person who is not an employee of an Employer but who performs services for an Employer pursuant to a leasing agreement (oral or written) between an Employer and any leasing organization, provided that such person has performed such services for an Employer or for related persons (within the meaning of Code Section 144(a)(3)) 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 an Employer. Notwithstanding the preceding sentence, the term “Leased Employee” shall not include any individual who is deemed to be an employee of an Employer under Code Section 414(n)(5).

1.27 Member: An Employee who, pursuant to the provisions of Article III, has met the eligibility requirements for participation in this Plan and is participating in the Plan.

1.28 Plan: The Cabot Oil & Gas Corporation Savings Investment Plan, as amended and restated effective January 1, 2001, set forth herein, and as hereafter amended from time to time.

1.29 Plan Quarter: Each calendar quarter of the Plan Year.

1.30 Plan Year: The fiscal year of the Plan beginning on January 1 of each calendar year and ending on December 31.

1.31 Pre-Tax Contribution Account: The account maintained for a Member to record his Pre-Tax Contributions and adjustments relating thereto.

5

1.32 Prior Plan: The Cabot Oil and Gas Corporation Savings Investment Plan, as established effective January 1, 1991, as thereafter amended and in effect on December 31, 2000.

1.33 Profit Sharing Plan: The Cabot Corporation Profit Sharing and Savings Plan as in effect on December 31, 1990.

1.34 Profit Sharing Plan Account: The account maintained for a Member who participated in the Profit Sharing Plan prior to January 1, 1991 to record his contributions from the Prior Plan and adjustments relating thereto.

1.35 Retirement Date: The sixty-fifth (65th) birthday of a Member or, if earlier, the date on which a Member who is a participant in the Cabot Oil and Gas Pension Plan satisfies the age and service requirements for Early Retirement under said pension plan.

1.36 Rollover Account: The account maintained for a Member to record his Rollover Amount and adjustments relating thereto.

1.37 Rollover Amount: For purposes of the Plan, one or more distributions (i) within one (1) taxable year of the employee on account of a termination of the plan of which the trust is a part, or in the case of a profit-sharing or stock bonus plan, a complete discontinuance of contributions under such plan or (ii) which constitute a lump-sum distribution within the meaning of subsection 402(e)(4)(A) of the Code (determined without reference to subparagraphs (B) and (H) of subsection 402(e)(4)). “Rollover Amount” may also include a transfer of assets from another qualified plan described in Code Section 401(a) which are attributable to the Member’s interests in such other plan if (i) such other plan does not permit distributions to be made in the form of life annuities, (ii) such other plan is a defined contribution plan which is not subject to the minimum funding standards of Code Section 412 and which satisfies all the conditions for exclusion from the requirements of Code Section 401(a)(11) set forth in Treasury Regulations Section 1.401(a)-20, Q&A 3(a), or (iii) such other plan provides for distributions in the form of life annuities but the transfer meets all the requirements of Treasury Regulations Section 1.411(d)-4, Q&A 3(b), as conclusively determined by the Committee, in order that this Plan, upon acceptance of such transfer, shall not thereafter be required to provide for distributions in the form of life annuities.

1.38 Service: A Member’s period of employment or deemed employment with Employers or Affiliates determined in accordance with Section 1.21 and Article III.

1.39 Total and Permanent Disability: A Member shall be considered totally and permanently disabled if (a) such disability is so certified by the Committee, on the basis of evidence satisfactory to the Committee, that such Member will be permanently incapable of performing a meaningful job for physical or mental reasons and such disability has lasted for at least six (6) months and (b) such Member is eligible for and receiving disability benefits under the Federal Social Security Act with respect to such condition. The Committee shall determine whether a Member has become totally and permanently disabled and shall so notify such Member within sixty (60) days thereafter.

1.40 Trust: The Trust created by and under the Trust Agreement.

6

1.41 Trust Agreement: The Trust Agreement provided for in Article IX, as amended from time to time.

1.42 Trust Fund: The Investment Funds held by the Trustee under the Trust Agreement, together with all income, profits or increments thereon.

1.43 Trustee: The trustee under the Trust Agreement.

1.44 Valuation Date: The last business day of each calendar quarter during the Plan Year and any other date on which the value of the assets of the Trust Fund is determined by the Trustee pursuant to Section 5.4; and the last business day of December of each Plan Year shall be the “Annual Valuation Date.”

1.45 Vesting Service: The period of a Member’s employment considered in the determination of his eligibility for benefits under the Plan. A year of Vesting Service shall be granted for each Plan Year during which an Employee completes at least 1,000 Hours of Service.

1.46 Year of Service: An Employment Year during which the Employee performs at least 1,000 Hours of Service.

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 may be appropriate under any particular circumstances.

7

ARTICLE II

ADMINISTRATION OF THE PLAN

2.1 Allocation of Responsibility Among Fiduciaries for Plan and Trust Administration: Each Employer, the Board of Directors of the Company, the Committee and the Trustee (hereinafter collectively referred to as the “Fiduciaries”) shall have only those specific powers, duties, responsibilities and obligations as are specifically given them under this Plan or the Trust Agreement. In general, each Employer shall have the sole responsibility for making the contributions provided for under Sections 4.1A and 4.2. The Board of Directors of the Company shall have the sole authority to appoint and remove the Trustee and the members of the Committee, and to amend or terminate, in whole or in part, this Plan or the Trust Agreement. The Committee shall have the sole responsibility for the administration of this Plan and the sole authority to appoint or remove any Investment Manager which may be provided for under the Trust Agreement. The Trustee shall have the sole responsibility for the administration of the Trust and shall have exclusive authority and discretion to manage and control the Trust Fund, except to the extent that the authority to manage, acquire and dispose of assets of the Trust Fund is delegated to an Investment Manager, all as more 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.

2.2 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 of the Company. All usual and reasonable expenses of the Committee may be paid in whole or in part by the Company, and any expenses not paid by the Company 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 Company 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 thereof.

2.3 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 Members’ Service, Account balances and the percentage of such Account balances which are non-forfeitable under the Plan, and notifications to Members. The Committee shall file or cause to be filed with the appropriate offices of the Internal Revenue Service and the Department of Labor all reports, returns, notices and other

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information required of plan administrators under ERISA, including, but not limited to, the summary plan description, annual reports and amendments thereto. The Committee shall make available to Members 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.

2.4 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 construe and interpret the Plan, reconcile any inconsistency or supply any omitted detail consistent with the general terms of the Plan, decide all questions of eligibility and determine the amount, manner and time of payment of any benefits hereunder;

(b) To prescribe procedures to be followed by Members or Beneficiaries filing applications for benefits;

(c) To receive from the Employers and from Employees 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 Employers, upon request, such annual reports with respect to the administration of the Plan as are reasonable and appropriate;

(f) To give written directions to the Trustee, on behalf of Members, as to the investment and reinvestment of the Trust Fund;

(g) To receive and review reports of the financial condition, and of the receipts and disbursements, of the Trust Fund from the Trustee and any Investment Manager, and to transmit such reports, along with its findings and recommendations surrounding the investment performance of the Trust Fund, to the Board of Directors; and

(h) To appoint or employ individuals to assist in the administration of the Plan and any other agents it deems advisable, including legal and actuarial counsel.

2.5 Rules and Decisions: The Committee may adopt such rules for the administration of the Plan 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 a Member or Beneficiary, an Employer, the legal counsel of an Employer or the Trustee.

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2.6 Committee Procedure: 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 or the Trustee. 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. The Committee shall designate one of its members as agent of the Plan and of the Committee for service of legal process at the principal office of the Committee at 15375 Memorial Drive, Houston, Texas 77079.

2.7 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.

2.8 Payment of Expenses: All reasonable and necessary expenses incident to the administration, termination or protection of the Plan and Trust, including, but not limited to, legal, accounting, Investment Manager and Trustee fees, shall be paid from the Trust Fund to the extent permitted by ERISA.

2.9 Application and Forms for Benefits: The Committee may require an Employee or Member to complete and file with the Committee an application for a benefit 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 Employee’s or Member’s current mailing address.

2.10 Committee Liability: Except to the extent that such liability is created by ERISA, no member 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 wilful 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 wilful misconduct of such member.

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2.11 Statements: As soon as practicable after each Valuation Date, the Committee shall prepare and deliver to each Member a written statement showing as of that Valuation Date:

(a) The balance in his Account in the Trust Fund as of the preceding Valuation Date;

(b) The amount of Employer Contributions allocated to his Employer Contribution Account and the amount of his Contributions for the Plan Year ending on such Valuation Date;

(c) The adjustments to his Account to reflect his share of income and expenses of the Trust Fund and appreciation or depreciation in Trust Fund assets during the Plan Year ending on such Valuation Date;

(d) The new balance in his Account as of that Valuation Date; and

(e) Such information as the Committee deems appropriate to advise him of his relative interests in each Investment Fund as of the preceding Valuation Date and the current Valuation Date.

2.12 Annual Audit: If required by ERISA, the Committee shall engage, on behalf of all Members, an independent Certified Public Accountant who shall conduct an annual examination of any financial statements of this Plan and Trust and of other books and records of this Plan and Trust 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 or furnished to each Member are presented fairly and in conformity with generally accepted accounting principles applied on a basis consistent with that of the preceding Plan Year. If, however, the statements required to be submitted as part of the reports to the Department of Labor are prepared by a bank or similar institution or insurance carrier regulated and supervised and subject to periodic examination by a state or federal agency and if such statements are certified by the preparer as accurate and if such statements are, in fact, made a part of the annual report to the Department of Labor and no such audit is required by ERISA, then the audit required by the foregoing provisions of this Section shall be optional with the Committee.

2.13 Funding Policy: The Committee shall, at a meeting duly called for such purpose, establish a funding policy and method consistent with the objectives of the 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 and the reasons therefor shall be recorded in the minutes of meetings of the Committee and shall be communicated to the Trustee, any Investment Manager who may be managing a portion or all of the Trust Fund in accordance with the provisions of the Trust Agreement, and to the Board of Directors.

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2.14 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 Trust Agreement 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 and/or Trust Agreement. Any such allocation or designation shall be made pursuant to a written instrument executed by a majority of the members of the Committee.

2.15 Presenting Claims for Benefits: Any Member or the Beneficiary of any deceased Member may submit written application to the Committee for 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 Committee may reasonably request. Promptly upon the receipt of any application required by this Section, the Committee shall determine whether or not the Member or Beneficiary involved is entitled to a benefit hereunder and, if so, the amount thereof and shall notify the claimant of its findings. Benefits under the Plan will be paid only if the Committee decides in its discretion that the applicant is entitled to them.

If a claim is wholly or partially denied, the Committee shall so notify the claimant within ninety (90) days after receipt of the claim by the Committee, unless special circumstances require an extension of time for processing the claim. If such an extension of time for processing is required, written notice of the extension shall be furnished to the claimant prior to the end of the initial ninety-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 Committee expects to render its final decision. Notice of the Committee’s decision to deny a claim in whole or in part shall be set forth in a manner calculated to be understood by the claimant 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 claimant to perfect the claim and an explanation of why such material or information is necessary, and

(iv) an explanation of the claims review procedure set forth in Section 2.16 hereof.

If notice of denial is not furnished, and if the claim is not granted within the period of time set forth above, the claim shall be deemed denied for purposes of proceeding to the review stage described in Section 2.16.

2.16 Claims Review Procedure: If an application filed by a Member or Beneficiary under Section 2.15 above shall result in a denial by the Committee of the benefit applied for, either in whole or in part, such applicant shall have the right, to be exercised by written application filed with the Committee within sixty (60) days after receipt of notice of the denial of his application or, if no such notice has been given, within sixty (60) days after the application is deemed denied under Section 8.4, to request the review of his application and of his entitlement to the benefit applied for. Such request for review may contain such additional information and comments as the applicant may wish to present. Within sixty (60) days after receipt of any such request for review, the Committee shall reconsider the application for the benefit 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. The Committee shall also permit the applicant or his designated representative to review pertinent 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 make a final determination with respect to the applicant’s application for review as soon as practicable, and in any event not later than sixty (60) days after receipt of the aforesaid request for review, except that under special circumstances, such as the necessity for holding a hearing, such sixty-day period may be extended to the extent necessary, but in no event beyond the expiration of one hundred twenty (120) days after receipt by the Committee of such 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. Notice of such final determination of the Committee shall be furnished to the applicant in writing, in a manner calculated to be understood by him, and shall set forth the specific reasons for the decision and specific references to the pertinent provisions of the Plan upon which the decision is based. If the decision on review is not furnished within the time period set forth above, the claim shall be deemed denied on review.

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ARTICLE III

PARTICIPATION AND SERVICE

3.1 Eligibility for Participation: An Employee participating under the Prior Plan immediately preceding January 1, 2001 shall continue to participate in accordance with the provisions of this Plan. Each other Employee shall be eligible to commence participation in this Plan on the Entry Date coincident with or next following his commencement of Service, provided he is otherwise eligible hereunder. An Employee who does not participate in the Plan when he first becomes eligible may commence participation on any Entry Date thereafter, provided he is otherwise eligible hereunder.

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 Notification of Eligible Employees: The Committee, which shall be the sole judge of the eligibility of an Employee to participate under the Plan, shall notify each Employee of his initial eligibility to participate in the Plan.

3.3 Applications by Employees: Each Employee who shall become eligible to become a Member under the Plan, and who shall desire to become a Member, shall execute and file with the Committee an application to become a Member in such form and manner as may be prescribed by the Committee. In each such application, the applicant shall (i) designate the amount of his Contributions to the Plan, (ii) agree to be bound by the terms and conditions of the Plan, (iii) designate a Beneficiary in accordance with Section 8.2, (iv) authorize payroll deductions for his Contributions, and (v) direct the investment of his Contributions among the Investment Funds in accordance with Sections 9.3 and 9.4.

3.4 Authorized Absences: An Employee’s or Member’s period of Service shall include the following Authorized Leaves of Absence:

(a) Absence due to accident or sickness so long as the person is continued on the employment rolls of the Employer or Affiliate and remains eligible to return to work upon his recovery;

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(b) Absence due to membership in the service of 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 or Affiliate) 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 person has complied with all prerequisites of such federal law; and

(c) Absence due to an authorized leave of absence granted by the Employer or Affiliate for any other purpose approved by the Board of Directors in accordance with established practices of the Employer or Affiliate, consistently applied in a non-discriminatory manner in order that all employees under similar circumstances shall be treated alike, provided that each such person shall, immediately upon the expiration of such leave, apply for reinstatement in the employment of the Employer or Affiliate.

3.5 Break In Service: For purposes of the Plan, a “Break In Service” shall mean a Plan Year within which a Member completes less than 501 Hours of Service. Solely for purposes of determining whether a Member has a Break In Service for eligibility or vesting purposes an individual who is absent from work for maternity or paternity reasons shall receive credit for the Hours of Service which would have otherwise been credited to such an individual but for such absence, or in any case in which such hours cannot be determined, eight hours of service per day of such absence. 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. The Hours of Service credited under this paragraph shall be credited (i) in the computation period in which the absence begins if the crediting is necessary to prevent a Break In Service in that period or (ii) in all other cases, in the following computation period. No more than 501 Hours of Service shall be credited for any single such absence.

3.6 Participation and Vesting Service Upon Re-employment Before a Break In Service: Upon the re-employment before a Break In Service of any person who had previously been employed by an Employer or Affiliate on or after the Effective Date, the following rules shall apply. If the re-employed person was not a Member during his prior period of Service, he shall be eligible to commence participation in the Plan on the first Entry Date after his re-employment upon meeting the requirements of Section 3.1. If the re-employed person was a Member in the Plan during his prior period of Service, he shall be entitled to recommence participation as of the date of his re-employment if eligible under Section 3.1. All years of Vesting Service attributable to a re-employed person’s prior period of Service shall be reinstated as of the date of his re-employment for purposes of Section 7.4.

3.7 Participation and Vesting Service Upon Re-employment After a Break In Service: Upon the re-employment after a Break In Service of any person who had previously been employed by an Employer or Affiliate on or after the Effective Date, the following rules shall apply in determining his eligibility for participation and his Vesting Service:

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(a) Participation: If an Employee (whether or not previously a Member) is rehired after cancellation of pre-break Service as determined in accordance with subparagraph (b) below, he must meet the requirements of Section 3.1 for participation in the Plan as if he were a new Employee. If an Employee is rehired prior to cancellation of his pre-break Service as determined in accordance with subparagraph (b) below, he shall be eligible to commence or recommence participation as of the date of his re-employment, if he previously was a Member and he meets the requirements under Section 3.1, or on the first Entry Date after his re-employment as of which he has completed the requirements of Section 3.1.

(b) Vesting Service: If the re-employed person was a Member whose prior Service terminated without entitlement to a distribution from his Employer Contribution Account under Article VII, any Vesting 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 Vesting Service. If the re-employed person was a Member whose prior Service terminated with entitlement to a distribution from his Employer Contribution Account under Article VII, all years of Vesting Service attributable to his prior period of employment shall be reinstated upon his recommencing participation in the Plan.

3.8 Vesting Service: An Employee shall be credited with one and only one year of Vesting Service for each Plan Year in which such Employee completes at least 1,000 Hours of Service for an Employer or Affiliate. An Employee will not be credited with a year of Vesting Service with respect to a Plan Year if the Employee completes less than 1,000 Hours of Service for the Employer or an Affiliate during such Plan Year. An Employee’s service with Cabot Corporation prior to the Effective Date shall count as Vesting Service under this Plan to the extent and in the same manner as computed under the Profit Sharing Plan.

3.9 Transferred Members: If a Member is transferred to an Affiliate, or to an employment classification with an Employer which is not covered by this Plan, his participation shall be suspended until he is subsequently re-employed by an Employer in an employment classification covered by the Plan; provided, however, that during such suspension period (i) such Member shall be credited with Service in accordance with Section 3.4, (ii) he shall not be entitled or required to make Savings Contributions under Section 4.1, (iii) his Employer Contribution Account shall receive no Employer Contribution except to the extent provided in Section 4.2, and (iv) his Account shall continue to share proportionately in Income of the Trust Fund as provided in Section 5.2. If an individual is transferred from an employment classification with an Employer that is not covered by the Plan to an employment classification that is so covered, or from an Affiliate to an employment classification with an Employer that is so covered, his period of Service prior to the date of transfer shall be considered for purposes of determining his eligibility to become a Member under Section 3.1 and for purposes of vesting under Section 7.4.

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3.10 Special Eligibility and Vesting for Certain Employees:

(a) Doran Employees. Effective March 1, 1989, all Employees who became Employees of an Employer as a result of the acquisition of certain assets of Doran & Associates, Inc. (“Doran”) shall become Members of the Plan subject to the eligibility requirements under Section 3.1. Any period of employment with Doran or an affiliate of Doran shall be considered for purposes of determining such Employees’ Service under the Plan to the extent such employment otherwise qualified under the relevant provisions of the Plan.

(b) Emax Employees. Effective October 1, 1993, all Employees who became Employees of an Employer as a result of the acquisition of certain assets of Emax Oil Company (“Emax”), shall become Members of the Plan subject to the eligibility requirements under Section 3.1. Any period of employment with Emax or an affiliate of Emax shall be considered for purposes of determining such Employees’ Service under the Plan to the extent such employment otherwise qualifies under the relevant provisions of the Plan.

(c) WERCO Employees. Effective May 3, 1994, all Employees who became Employees of an Employer as a result of the merger with Washington Energy Resources Company (“WERCO”), shall become Active Participants of the Plan subject to the eligibility requirements under Section 3.1. Any period of employment with WERCO or an affiliate of WERCO shall be considered for purposes of determining such Employees’ Service under the Plan to the extent such employment otherwise qualifies under the relevant provisions of the Plan.

(d) Castle Gas Employees. Effective April 13, 1998, all Employees who became Employees of an Employer as a result of the acquisition of certain assets of Castle Gas Company, Inc. (“Castle Gas”) shall become Active Participants of the Plan subject to the eligibility requirements under Section 3.1. Any period of employment with Castle Gas or an affiliate of Castle Gas shall be considered for purposes of determining such Employees’ Service under the Plan to the extent such employment otherwise qualifies under the relevant provisions of the Plan.

(e) Oryx Employees. Effective December 30, 1998, all Employees who became Employees of an Employer as a result of the acquisition of certain properties of Oryx Energy Company (“Oryx”), shall become Active Participants of the Plan subject to the eligibility requirements under Section 3.1. Any period of employment with Oryx or an affiliate of Oryx shall be considered for purposes of determining such Employees’ Service under the Plan to the extent such employment otherwise qualifies under the relevant provisions of the Plan.

3.11 Automatic Vesting 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.

3.12 Qualified Military Service: 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.

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ARTICLE IV

CONTRIBUTIONS AND FORFEITURES

4.1 Savings Contributions: Each Member may designate up to fifteen percent (15%) of his Compensation as Pre-Tax and/or After-Tax Contributions as described herein.

A. Pre-Tax Contributions: Each Member who elects to make Pre-Tax Contributions for a Plan Year shall initially elect to defer a portion of his Compensation in whole percentages of not less than one percent (1%) and not more than fifteen percent (15%) (to the nearest whole dollar) of his Compensation; provided, however, that Pre-Tax Contributions and After-Tax Contributions under this Section 4.1 shall not total, in the aggregate, more than fifteen percent (15%) (to the nearest whole dollar) of the Member’s Compensation. Such deferred percentage shall be applied against a Member’s Compensation as such Compensation becomes payable. Each such election shall continue in effect during subsequent Plan Years unless the Member notifies the Committee, in writing and in such form and manner prescribed by the Committee, of his election to change or discontinue his Pre-Tax Contribution. A Member may change the percentage of his Compensation designated by him as his Pre-Tax Contribution, but not retroactively and not more frequently than four (4) times each Plan Year. A Member’s Pre-Tax Contributions shall not exceed a maximum of $10,500 as adjusted by the Secretary of the Treasury to account for cost-of-living increases. In the event a Member’s Pre-Tax Contributions exceed the applicable $10,500 limit, or in the event the Member submits a written claim to the Committee, at the time and in the manner prescribed by the Committee, specifying an amount of Pre-Tax Contributions that will exceed the applicable limit of Section 402(g) of the Code when added to amounts deferred by the Member in other plans or arrangements, such excess (the “Excess Deferrals”), plus any income and minus any loss attributable thereto, shall be returned to the Member by April 15 of the following year. Such income shall include the allocable gain or loss for (i) the Plan Year in which the Excess Deferral occurred and (ii) the period from the end of that Plan Year to the date of distribution. The amount of any Excess Deferrals to be distributed to a Member for a taxable year shall be reduced by excess Pre-Tax Contributions previously distributed pursuant to Article XIV for the Plan Year beginning in such taxable year. The income or loss attributable to the Member’s Excess Deferral for the Plan Year shall be determined by multiplying the income or loss attributable to the Member’s Pre-Tax Contribution Account balance for the Plan Year (or relevant portion thereof) by a fraction, the numerator of which is the Excess Deferral and the denominator of which is the Member’s total Pre-Tax Contribution Account balance as of the Valuation Date next preceding the date of return of the Excess Deferral. Unless the Committee elects otherwise, the income or loss attributable to the Member’s Excess Deferral for the period between the end of the Plan Year and the date of distribution shall be determined using the safe-harbor method set forth in Treasury Regulations to Section 402(g) of the Code, and shall be equal to ten percent (10%) of the allocable income or loss for the Plan Year, calculated as set forth immediately above, multiplied by the number of calendar months that have elapsed since the end of the Plan Year. For these purposes, distribution of an Excess Deferral on or before the fifteenth (15th) day of a calendar month shall be treated as having been made on the last day of the preceding month, and a distribution made thereafter shall be treated as having been made on the first day of the next month. Any Excess Deferrals which have not been returned to the Member by April 15 of the following year shall be

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treated as Annual Additions under Article XII of the Plan. Each Member’s Pre-Tax Contribution shall be contributed to the Trust Fund by the Employer. A Member shall always be fully vested in and have a non-forfeitable right to his Pre-Tax Contributions.

B. After-Tax Contributions: Any Member regardless of whether he has elected to defer any whole percentage of his Compensation in the form of a Pre-Tax Contribution to the Plan may elect to make an After-Tax Contribution of up to fifteen percent (15%) (to the nearest whole dollar) of his Compensation; provided, however, that Pre-Tax Contributions and After-Tax Contributions under this Section 4.1 shall not total, in the aggregate, more than fifteen percent (15%) (to the nearest whole dollar) of the Member’s Compensation. Such a deferred percentage shall be applied against a Member’s Compensation as such Compensation becomes payable. Any After-Tax Contribution election shall be made pursuant to the provisions of Section 3.3, and shall continue in effect during subsequent Plan Years unless the Member notifies the Committee, in writing and in such form and manner prescribed by the Committee, of his election to change or discontinue his After-Tax Contribution. A Member may change the percentage of his Compensation designated by him as his After-Tax Contribution; provided, however, that he may not change his Pre-Tax and After-Tax Contribution elections in the aggregate more than four (4) times each Plan Year and that such changes shall not be retroactive. A Member shall always be fully vested in and have a non-forfeitable right to his After-Tax Contributions.

4.2 Employer 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. “Basic Savings Contributions” means each Member’s first six percent (6%) of Pre-Tax Contributions. An Employer Contribution 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. All Employer Contributions shall be paid to the Trustee, and payment shall be made not 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. The Trustee shall hold all such Employer Contributions subject to the provisions of this Plan and Trust, and no part of such Contributions shall be used for, or diverted to, any other purpose. The foregoing not withstanding, with respect to a Member who defers his Compensation at a rate of 6% or more and who, prior to the end of the Plan Year, ceases his contributions because of the limits imposed by Code Section 402(g), Employer Contributions to his Employer Contribution Account shall be made each pay period for such Plan Year in such an amount that the aggregate of such contributions for such Plan Year is equal to the amount provided by the Employer pursuant to this Section.

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. All such “Employer Minimum Contributions” shall be transmitted to the Trustee as soon as practicable after such contributions are made.

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4.3 Employer Contributions and Pre-Tax Contributions to be Tax Deductible: Employer Contributions and Pre-Tax Contributions shall not be made in excess of the amount deductible under applicable federal law now or hereafter in effect limiting the allowable deduction for contributions to profit-sharing plans. The Employer Contributions and Pre-Tax Contributions to this Plan, when taken together with all other contributions made by the Employer to other qualified retirement plans, shall not exceed the maximum amount deductible under Section 404 of the Code.

4.4 Suspension of Contributions: Any Member may, by written direction to his Employer, suspend his Pre-Tax Contributions and/or After-Tax Contributions at any time by giving at least twenty-one (21) days’ notice. In the case of any suspension of Pre-Tax Contributions and/or After-Tax Contributions, the Employer Contributions will automatically cease. Pre-Tax Contributions and/or After-Tax Contributions which are not made during a period of suspension shall not be made up retroactively.

4.5 Delivery to Trustee: Each Employer shall, not less frequently than monthly, pay the Contributions to the Trustee.

4.6 Application of Funds: The Trustee shall hold or apply the Contributions so received by it subject to the provisions of the Plan; and no part thereof (except as otherwise provided in the Trust Agreement) shall be used for any purpose other than the exclusive use of the Members or their Beneficiaries.

4.7 Rollover Amounts: Any Member may file with the Committee a written request that the Trustee accept a Rollover Amount from such Member. The Committee, in its sole and absolute discretion, shall determine whether such Member shall be permitted to contribute a Rollover Amount to the Trust Fund. The Committee shall develop such procedures and may require such information from the Employee or Member desiring to make such a transfer as it deems necessary or desirable to determine that the proposed transfer will meet the requirements of this Section. Upon approval by the Committee, the amount transferred shall be deposited in the Trust Fund and shall be credited to a separate Rollover Account. Such account shall at all times be one hundred percent (100%) vested in the Employee or Member and shall share in the Income of the Trust Fund in accordance with Section 5.2. Upon termination of employment, the total amount of the Rollover Account shall be distributed in accordance with Article VIII.

Upon such a transfer by an Employee who is otherwise eligible to participate in the Plan but who has not yet completed the participation requirements of Section 3.1, his Rollover Account shall represent his sole interest in the Plan until he becomes a Member. In all respects, the Rollover Account shall be treated as a regular account under this Plan and shall be subject to the investment directions of the Member and the change thereof as otherwise permitted herein.

4.8 Disposition of Forfeitures: If a Member terminates Service without being entitled to receive a distribution from his Employer Contribution Account, he shall be deemed to have received a distribution from that Account as of the date of his termination of Service. Upon termination of Service, a Member’s Forfeiture (as defined in Section 1.21), if any, shall first be

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credited to the Employer Contribution Account of a re-employed Member for whom a reinstatement of prior Forfeitures is required pursuant to Section 7.4 hereof, and second shall be applied toward the Account of a former Member pursuant to the unclaimed benefit provisions of Section 11.10 hereof. To the extent that Forfeitures for any Plan Year exceed the amounts required to reinstate the Accounts noted above, they will be applied against the next succeeding Employer Contribution.

4.9 Contributions Generally Irrevocable: All Employer contributions to the Trust Fund shall be irrevocable and shall be used to pay benefits or to pay expenses of the Plan and Trust Fund; provided, however, that upon the Employer’s request, a contribution which was made by a mistake of fact or conditioned upon initial qualification of the Plan and Trust Fund under Sections 401(a) and 501(a) of the Code, or upon the deductibility of the contribution under Section 404 of the Code, shall be returned to the Employer within one (1) year after the payment of the contribution, the denial of initial qualification or the disallowance of the deduction (to the extent disallowed), whichever is applicable.

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ARTICLE V

MEMBER ACCOUNTS

5.1 Individual Accounts: The Committee shall create and maintain adequate records to disclose the interest in the Trust Fund and in its component Investment Funds of each Member, former Member and Beneficiary. Such records shall be in the form of individual accounts and credits and charges shall be made to such accounts in the manner herein described. A Member may have up to nine (9) separate accounts, including but not limited to, an Employer Contribution Account, a Pre-Tax Contribution Account, an After-Tax Contribution Account, a Profit Sharing Plan Account, an ESOP Account and a Rollover Account. Any Member who transfers from one Employer to another Employer, or who is simultaneously employed by two or more Employers, may have individual accounts with each such Employer. The maintenance of individual Accounts is only for accounting purposes, and a segregation of the assets of the Trust Fund to each Account shall not be required. Distribution and withdrawals made from an Account shall be charged to the Account as of the date paid.

5.2 Account Adjustments: The Accounts of Members, former Members and Beneficiaries shall be adjusted each Plan Year in accordance with the following:

(a) Income of the Trust Fund: Each Valuation Date, the Trustee shall value the Trust Fund at its then market value to determine the amount of Income of the Trust Fund. The Income of the Trust Fund since the preceding Valuation Date (including the appreciation or depreciation in value of the assets of the Investment Fund) shall be allocated to the Accounts of Members in proportion to the balances in such Accounts on the preceding Valuation Date, but after first reducing each such Account balance by any distribution from such Account since the preceding Valuation Date and increasing such Account balance by any Contributions and loan payments since the preceding Valuation Date.

(b) Savings Contributions: As of each Valuation Date during the Plan Year, the Trustee shall allocate to each respective Member’s Pre-Tax Contribution Account his Pre-Tax Contributions to the Plan made since the preceding Valuation Date. As of each Valuation Date during the Plan Year, the Trustee shall also allocate to each respective Member’s After-Tax Contribution Account his After-Tax Contributions made since the preceding Valuation Date.

(c) Employer Contributions: No less frequently than the Annual Valuation Date and more frequently as may be specified by the Committee, the Employer Contribution for such Plan Year shall be allocated among its Members during such Plan Year or partial Plan Year in the ratio that each Member’s unwithdrawn Basic Savings Contributions for the 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.

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(d) Forfeitures: Forfeitures which have become available for reallocation during such Plan Year shall be applied pursuant to Section 4.8.

(e) Employer Minimum Contributions: Employer Minimum Contributions shall be used solely to reinstate Accounts in accordance with Section 7.4 and to restore Accounts pursuant to Section 11.10 whenever the Forfeitures available for such reinstatement or restoration are insufficient.

5.3 Recognition of Different Investment Funds: As provided in Article IX, Investment Funds shall be established and each Member shall direct, within the limitations set forth in Sections 9.3 and 9.4, what portion of the balance in his Accounts on a pro rata basis, if any, shall be deposited in each Investment Fund. Consequently, when appropriate, a Member shall have an Employer Contribution Account, Pre-Tax Contribution Account, After-Tax Contribution Account, Profit Sharing Plan Account and Rollover Account in each such Investment Fund and the allocations described in Section 5.2 shall be adjusted in such manner as is appropriate to recognize the existence of the Investment Funds. Because Members have a choice of Investment Funds, any reference in this Plan to an Employer Contribution Account, Pre-Tax Contribution Account, After-Tax Contribution Account, Profit Sharing Plan Account or Rollover Account shall be deemed to mean and include all accounts of a like nature which are maintained for the Member under each Investment Fund.

5.4 Valuation of Trust Fund: A valuation of the Trust Fund shall be made as of each Valuation Date and on any other date during the Plan Year that the Committee deems a valuation to be advisable. Any such interim valuation shall be exercised on a uniform and non-discriminatory basis. For the purposes of each valuation, the assets of each Investment Fund shall be valued at the respective current market values, and the amount of any obligations for which the Investment Fund may be liable, as shown on the books of the Trustee, shall be deducted from the total value of the assets. For the purposes of maintenance of books of account in respect of properties comprising the Trust Fund, and of making any such valuation, the Trustee shall account for the transactions of the Trust Fund on a modified cash basis. The current market value shall, for the purposes hereof, be determined as follows:

(a) Where the properties are securities which are listed on a securities exchange, or which are actively traded over the counter, the value shall be the last recorded bid and asked prices, whichever shall be the later. In the event transactions regarding such property are recorded over more than one such exchange, the Trustee may select the exchange to be used for purposes hereof. Recorded information regarding any such securities published in The Wall Street Journal or any other publication deemed appropriate may be relied upon by the Trustee. If no transactions involving any such securities have been recorded within ten (10) days prior to the particular Valuation Date, such securities shall be valued as provided in paragraph (b) below.

(b) Where paragraph (a) hereof shall be inapplicable in the valuation of any properties, the Trustee shall obtain from at least two (2) qualified persons an opinion as to the value of such properties as of the close of business on the particular Valuation Date. The average of such estimates shall be used.

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ARTICLE VI

WITHDRAWALS AND LOANS

6.1 Withdrawals from Profit Sharing Plan Account: Each Member with a Profit Sharing Plan Account shall be entitled to withdraw such amounts that were transferred to this Plan. The following withdrawals are permitted only from a Member’s Profit Sharing Plan Account:

A. Voluntary Withdrawals: Each Member of the Plan, upon giving written notice to the Committee (in such form and in such manner as prescribed by the Committee) shall be entitled to withdraw from his Profit Sharing Plan Account (valued as of the Valuation Date preceding the actual date of the withdrawal) any amount, not to exceed the balance of such Account, as of such date. Voluntary withdrawals shall be limited to two such withdrawals per year and further limited to only one such withdrawal in any given three-month period. Voluntary withdrawals shall be deducted from a Member’s Profit Sharing Plan Account in the following order:

4. Profit Sharing Plan after-tax contributions made before January 1, 1987.

5. Profit Sharing Plan after-tax contributions including investment earnings made after December 31, 1986.

6. Profit Sharing Plan investment earnings on after-tax contributions made before January 1, 1987.

7. Profit Sharing Plan vested employer contributions including investment earnings.

Notwithstanding any of the foregoing, the vested portion of employer contributions may only be withdrawn from the Profit Sharing Plan Account 24 months after such amounts were contributed to the Profit Sharing Plan.

B. Hardship Withdrawals: The following hardship withdrawals shall be allowed:

1. A Member may make a hardship withdrawal from his Profit Sharing Plan Account if the Member has already made two voluntary withdrawals or if three (3) months have not elapsed since the previous voluntary withdrawal.

2. A Member may at any time file with the Committee an appropriate written request for a hardship withdrawal of an amount from the pre-tax contribution account in his Profit Sharing Plan Account. Notwithstanding the foregoing, a Member may not withdraw any Income of the Trust Fund allocated to his pre-tax contribution account in his Profit Sharing Plan Account on or after January 1, 1989. The approval or disapproval of such request shall be made

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within the sole discretion of the Committee except that the Committee shall not approve any such request for a withdrawal unless it has been presented a certification by the Member that he is facing a hardship creating an immediate and substantial financial need and that the resources necessary to satisfy that financial need are not reasonably available from other sources of the Member. A Member must first withdraw any available amount credited to the after-tax account and the vested portion of his employer contribution account in his Profit Sharing Plan Account in order to be permitted to make a hardship withdrawal from the pre-tax contribution account in his Profit Sharing Plan Account, and must also have taken all distributions and loans otherwise available under this Plan and all employee plans maintained by the Member’s Employer. The amount of the hardship withdrawal shall be limited to that amount which the Committee determines to be required to meet the immediate financial need created by the hardship. The hardship withdrawal shall be made in cash as soon as practicable after the Member submits the hardship request and the dollar amount withdrawn shall be determined by reference to the value of the pre-tax contribution account in his Profit Sharing Plan Account as of the Valuation Date immediately preceding the date of withdrawal. A Member who receives such a hardship withdrawal shall be prohibited from making Pre-Tax Contributions under the Plan or pre-tax contributions under any other cash or deferred arrangement for the twelve (12) consecutive months following the date of distribution and in addition, the dollar limitation on the Pre-Tax Contributions described in Section 4.1 shall be reduced in the year following the hardship withdrawal by the amount of Pre-Tax Contributions made by the Member in the Plan Year during which the withdrawal was made. The following standards (or such other standards as may be acceptable under Treasury Regulations issued pursuant to Section 401(k) of the Code) shall be applied on a uniform and non-discriminatory basis in determining the existence of such a hardship:

(a) A financial need shall be considered immediate if it must be satisfied in substantial part within a period of twelve (12) months from the date on which the Member certifies his eligibility for a hardship withdrawal. A financial need shall be considered substantial if it exceeds ten percent (10%) of the Member’s annual Compensation.

(b) Subject to the provisions of Section 6.1(a) above, a distribution will be deemed by the Committee to be on account of an immediate and substantial financial need if it results from:

(i) medical expenses incurred by the Member, or the Member’s spouse or dependents (as defined in Section 152 of the Code),

(ii) purchase (excluding mortgage payments) of a principal residence for the Member,

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(iii) payment for tuition for the next semester or quarter of post-secondary education for the Member or the Member’s spouse, children or dependents, or

(iv) the need to prevent the eviction of the Member from his principal residence or foreclosure on the mortgage of the Member’s principal residence.

6.2 Withdrawals of Amounts From After-Tax Contribution Account: Each Member of the Plan, upon giving written notice to the Committee (in such form and in such manner as prescribed by the Committee), may elect to withdraw from his After-Tax Contribution Account those contributions which are made on or after January 1, 1991. The minimum amount of such withdrawal shall be $500. If a withdrawal is made to a Member before he attains age 59- ¹/2, the Member shall be advised by the Committee that in addition to taxes payable on investment earnings, an income tax may be imposed equal to ten percent (10%) of the amount so received which is included in his gross income for such taxable year.

6.3 Withdrawals of Amounts From Pre-Tax Account: A Member may not withdraw any amount from his Pre-Tax Account, except a Member who has attained age 59- ¹/2 may elect, by giving sixty (60) days’ written notice to the Committee (or within any other period of time as prescribed by the Committee) and by following such other rules and procedures as may be prescribed from time to time by the Committee on a uniform and non-discriminatory basis, to withdraw the entire amount or any portion of his Pre-Tax Contribution Account.

6.4 Withdrawals from Employer Contribution, ESOP and Rollover Accounts: A Member may not withdraw any amount from his Employer Contribution, ESOP or Rollover Accounts.

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. 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

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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 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 the 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 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 Account of such Borrower.

(g) A loan to a Borrower shall be considered an investment of the separate Account(s) of the Borrower from which the loan is made. All loan repayments shall be credited pro rata to such separate 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.

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ARTICLE VII

MEMBERS’ BENEFITS

7.1 Retirement of Members on or after Retirement Date: Any Member who terminates his Service on or after his Retirement Date shall have a fully vested and non-forfeitable right to receive the entire amount of his Account. The “entire amount” in such Member’s Account shall include any Savings Contributions, Rollover Amounts, amounts in the Profit Sharing Plan Account, ESOP Account and Employer Contributions to be made as of the Valuation Date preceding his termination of Service. Payment of benefits due under this Section shall be made in accordance with Section 8.1. Notwithstanding any provision of this Plan to the contrary, a Member’s right to the amounts credited to his Accounts hereunder shall become fully vested and non-forfeitable in the event of his attainment of age sixty-five (65) prior to termination of Service.

7.2 Disability of Members: If the Committee shall find and advise the Trustee that Service of a Member has been terminated because of Total and Permanent Disability, which in the judgment of the Committee, based upon advice of competent physicians of their selection, will prevent such Member from resuming his Service with an Employer, such Member shall become entitled to receive the entire amount of his Account. The “entire amount” in such Member’s Account shall include any Savings Contributions, Rollover Amounts, amounts in the Profit Sharing Plan Account, ESOP Account and Employer Contributions to be made as of the Valuation Date preceding his termination of Service. Payment of benefits due under this Section shall be made in accordance with Section 8.1.

7.3 Death of Members: In the event of the termination of Service of any Member by death, and after receipt by the Committee of acceptable proof of death, his Beneficiary shall be entitled to receive the entire amount in the deceased Member’s Account. The “entire amount” in such Member’s Account shall include any Savings Contributions, Rollover Amounts, amounts in the Profit Sharing Plan Account, ESOP Account and Employer Contributions to be made as of the Valuation Date preceding his termination of Service. Payment of benefits due under this Section shall be made in accordance with Section 8.2.

7.4 Other Termination of Service: In the event of termination of Service of any Member for any reason other than retirement on or after his Retirement Date, disability or death, a Member shall, subject to the further provisions of this Plan, be entitled to receive the entire amount credited to his Pre-Tax Contribution Account, After-Tax Contribution Account, amounts in the Profit Sharing Plan Account, ESOP Account, Rollover Account, plus any of his Savings Contributions made as of the Valuation Date preceding his termination of Service, plus an amount equal to the vested percentage of his Employer Contribution Account, determined in accordance with the following schedule:

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Years of Vesting Service	Vested Percentage
Less than 1 year	0	%
1 year but less than 2	20	%
2 years but less than 3	40	%
3 years but less than 4	60	%
4 years but less than 5	80	%
5 or more years	100	%

Any portion of the Employer Contribution Account of a terminated Member in excess of the vested percentage specified above shall be a Forfeiture, which shall be disposed of as provided in Section 4.8. Payment of benefits due under this Section shall be made in accordance with Section 8.1.

In addition, any amounts forfeited from the prior Employer Contribution Account of such Member upon his earlier termination of Service shall be reinstated to his new Employer Contribution Account. Upon the re-employment of any individual who had previously been a Member and who has incurred five consecutive Breaks In Service, such re-employed individual shall not be entitled to a reinstatement of any Forfeiture incurred by reason of his prior termination of employment.

If a distribution is made at a time when a Member is not fully vested in his Employer Contribution Account balance, and if the Member is re-employed prior to a Forfeiture of the balance of his Employer Contribution Account, the Member’s non-forfeitable portion of the balance of the undistributed Employer Contribution Account shall be reinstated to his new Employer Account (as provided in Section 4.8) within a reasonable time after repayment by the Member of the amount of his previous distribution, if any.

Notwithstanding anything herein to the contrary, if a Member (i) terminates Service prior to having completed five years of Vesting Service; (ii) meets the eligibility requirements for a severance plan approved by the Chief Executive Officer of the Company and the Committee and listed on Appendix A attached hereto; and (iii) if required by the applicable severance plan, signs a waiver and release, such Member shall be entitled to receive the entire amount credited to such Member’s Employer Contribution Account.

7.5 Valuation Dates Determinative of Member’s Rights: The amount to which a Member is entitled upon his retirement, disability, death or other termination of Service shall be valued as of the Valuation Date determined as follows:

(a) In the case of any Member whose Service is terminated due to his retirement on or after his Retirement Date, disability or death, the amount to which such Member or his Beneficiary is entitled upon such termination of Service shall be determined as of the last Valuation Date preceding his termination of Service.

(b) In the case of any Member whose Service is terminated for any reason other than retirement on or after his Retirement Date, disability or death, the amount to which such Member is entitled upon such termination of Service shall be valued as of the last Valuation Date preceding the Distribution Date as defined in Section 8.1.

7.6 Vesting for Certain Employees: Each Member who is eligible to participate in the 1992 Cabot Oil & Gas Corporation Severance Benefit Plan No. 506 and whose Service is terminated involuntarily between January 9, 1992 and January 21, 1992 shall be fully vested in and have a non-forfeitable right to his entire Account balance in the Plan as of the date of the termination of his Service with the Company.

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ARTICLE VIII

PAYMENT OF BENEFITS

8.1 Payment of Benefits: Upon a Member’s entitlement to payment of benefits under Section 7.1, 7.2 or 7.4, he shall file with the Committee his written election on such forms or forms, and subject to such conditions, as the Committee shall provide. Such benefit may be made in two distributions, the first such distribution consisting of the entire amount in such Member’s Account as of the Valuation Date preceding his termination of Service plus any Pre-Tax or After-Tax Contributions made by the Member subsequent to such Valuation Date, and the second distribution consisting of the Employer Contribution allocated to such Member’s Account as of the Valuation Date of the Plan Year in which such Member terminated Service. The Committee shall direct the Trustee to distribute the Member’s benefits according to the Member’s election.

The day following the date of the Member’s termination of Service is the earliest date that payment of his benefits may commence and is herein referred to as such Member’s “Distribution Date.” Payment of a Member’s benefits shall be made or commence as soon as practicable after his Distribution Date, subject to the Member’s election to defer receipt thereof, but in any event must be made or commence prior to the expiration of 60 days after the Valuation Date of the Plan Year within which such Member’s Retirement Date occurs or the date of his death, if earlier. A member who withholds consent to an immediate distribution may at any time, subsequently elect, in the form and manner prescribed by the Committee, to receive payment of benefits. If a benefit distribution under the Plan is made to a Member before he attains age 59- ¹/2, the Member shall be advised by the Committee that an additional income tax may be imposed equal to ten percent (10%) of the portion of the amount so received which is included in his gross income for such taxable year and which is attributable to benefits accrued while he was a Member. Members who terminate Service after attainment of age fifty-five (55) shall be notified of their exemption from said additional tax.

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 Corporation stock or shares of Cabot Oil and 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. The Profit Sharing Plan Account and the ESOP Account shall retain the payment options provided under the Profit Sharing Plan and the ESOP.

If the amount to which a terminated Member is entitled is not more than $5,000, such amount shall be paid to the Member as soon as practicable after his Distribution Date; if such amount is in excess of $5,000, the distribution shall be made only if the Member so consents. If such consent is withheld, distribution of the amount to which the terminated Member is entitled shall be made to such Member within 60 days after the end of the Plan Year in which occurs the earlier of the Member’s death or his Retirement Date. If a Member’s termination of Service occurs after his Retirement Date, distribution shall be made within 60 days after the end of the Plan Year in which termination occurs. If a Member dies before

29

distribution of his interest commences, the Member’s entire interest will be distributed no later than five years after the Member’s death. If distribution has commenced before the Member’s death, any remaining amount in the Member’s Account shall be distributed at least as rapidly as under the method of distribution being used as of the date of the Member’s death.

Notwithstanding anything herein to the contrary, if a distribution is one to which Code Sections 401(a)(11) and 417 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 Member that the Member 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 Member, 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 Member may elect, with the consent of the Member’s spouse 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.

8.2 Distribution Upon Death: In the event of the death of any Member, the amount in his Account shall be distributable as follows:

(a) A Member shall file with the Committee a written designation, in the form prescribed by the Committee, of the Beneficiary or Beneficiaries to receive the amount in his Account upon his death, and the Member may at any time change or cancel any such designation by filing a written request in the form prescribed by the Committee. No such designation of Beneficiary shall be effective if the Member has a spouse, unless the spouse is designated as the Beneficiary or unless the spouse consents to the designation of another person as Beneficiary or the absence of the spouse’s consent is permitted herein. The Member’s spouse may waive the right to be the Member’s sole Beneficiary and consent to the Beneficiary designation made by the Member. The waiver must (i) be in writing; (ii) designate a specific alternate Beneficiary and a form of benefit which may not be changed without spousal consent (or must expressly permit designation by the Member without further consent of the spouse); (iii) acknowledge the effect of the waiver; and (iv) be witnessed by a Plan representative or a notary public. The spouse’s consent to a Beneficiary designation shall not be required if it is established to the satisfaction of the Committee that such written consent may not be obtained because there is no spouse or the spouse cannot be located. Any consent under this Section 8.2(a) will be valid only with respect to the spouse who signs the consent. Additionally, a revocation of a prior spousal consent may be made by a Member without the consent of the spouse at any time before the distribution of the benefit under the Plan. The number of revocations shall not be limited.

(b) In the event of the death of any Member, the entire amount in the Account of such Member shall be distributed to the Member’s spouse, or if there

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is no spouse, or the spouse has consented pursuant to Section 8.2(a), then to the Beneficiary designated by him as provided in the preceding paragraph (a); or, in the absence of an effective designation or if no designated Beneficiary survives the Member, then to the duly appointed and qualified executor or administrator of the Member’s estate; or, if no administration of the estate of such decedent is necessary, then to the Beneficiary entitled thereto under the last will and testament of such deceased Member; or, if such decedent left no will, to the legal heirs of such decedent determined in accordance with the laws of intestate succession of the state of the decedent’s domicile.

(c) If the Committee shall be in doubt as to the right of any Beneficiary designated by a deceased Member to take the interest of such decedent, the Committee may direct the Trustee to distribute the amount in the Account in question to the estate of such Member, 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 in respect of the assets.

8.3 Required Minimum Distributions: Except as provided below, if a Member is employed by the Company on the April 1 following the calendar year in which the Member attains age 70- ¹/2 such Member may choose to commence distribution of any benefits to which the Member is entitled either on the April 1 of the calendar year following the calendar year in which (i) the Member attains age 70- ¹/2 or (ii) the Member retires from the Company. Notwithstanding any provision of the Plan to the contrary, any benefits to which a member who is a 5% owner of the Company is entitled shall commence not later than April 1 of the calendar year following the calendar year in which the Member attains age 70- ¹/2, whether or not his employment has terminated in such year. Such distribution shall be at least equal to the required minimum distributions under Section 401(a)(9) of the Code and the regulations thereunder. With respect to distributions under the Plan made for calendar years beginning on or after January 1, 2001, the Plan will apply the minimum distribution requirements of Section 401(a)(9) of the Code in accordance with the regulations under Section 401(a)(9) that were proposed on January 17, 2001, notwithstanding any provision of the Plan to the contrary. This amendment shall continue in effect until the end of the last calendar year beginning before the effective date of final regulations under Section 401(a)(9) or such other date as may be specified in guidance published by the Internal Revenue Service.

8.4 Disputed Benefits: If any dispute still exists between a Member or a Beneficiary and the Committee after a review of the claim or in the event any uncertainty shall develop as to the person to whom payment of any benefit hereunder shall be made, the Trustee may withhold the payment of all or any part of the benefits payable hereunder to the Member or Beneficiary until such dispute has been resolved by a court of competent jurisdiction or settled by the parties involved.

8.5 Member’s Right to Transfer Eligible Rollover Distribution:

A. Rule: 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

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time and in the manner prescribed by the plan administrator, to have any portion of an eligible rollover distribution paid directly to an eligible retirement plan specified by the distributee in a direct rollover.

B. Definitions:

(a) Eligible Rollover Distribution: An eligible rollover distribution is 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 specified period of ten (10) years or more; any distribution to the extent such distribution is required under Section 401(a)(9) of the Code; any hardship withdrawal described in Section 401(k)(2)(B)(i)(IV) 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: An eligible retirement plan is an individual retirement account described in Section 408(a) of the Code, an individual retirement annuity described in Section 408(b) of the Code, an annuity plan described in Section 403(a) of the Code, or a qualified trust described in Section 401(a) of the Code, that accepts the distributee’s eligible rollover distribution. However, in the case of an eligible rollover distribution to the surviving spouse, an eligible retirement plan is an individual retirement account or individual retirement annuity.

(c) Distributee: A distributee includes an Employee or former Employee. In addition, the Employee’s or former Employee’s surviving spouse and the Employee’s or former Employee’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: A direct rollover is a payment by the Plan to the eligible retirement plan specified by the distributee.

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ARTICLE IX

TRUST AGREEMENT; INVESTMENT

FUNDS; INVESTMENT DIRECTIONS

9.1 Trust Agreement: The Company has adopted a Trust Agreement governing the administration of the Trust, established effective as of January 1, 1991 (the provisions of which are herein incorporated by reference to the extent not inconsistent herewith). Subject to the provisions of Section 9.2, and, not by way of limitation, the provisions of the Trust Agreement, the Trustee may invest a portion of the Trust Fund in common stock of the Company, or in any other “qualifying employer security” within the meaning of Section 407(d)(5) of ERISA.

9.2 Investment Funds: The Trustee shall divide the Trust Fund into the Cabot Corporation Common Stock Fund; 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.

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. Notwithstanding any provision in this Section to the contrary, the Committee may direct the Trustee (i) to invest Savings or Employer Contributions in short-term fixed income investments which are acceptable to the Trustee or in the suspense account to be maintained in each Investment Fund during the period from the date of any such Contribution until the next Valuation Date or (ii) to invest all or any portion of the Trust Fund attributable to any terminated or retired Member or attributable to any Member who is expected to retire or to terminate his Service within one (1) year, in one or more fixed income investments which are acceptable to the Trustee. The fixed income investments authorized by this Section shall include, but not be limited to, certificates of deposit, savings accounts, or U.S. Treasury bills or notes.

9.3 Investment Directions of Members: Each Member may, in a form and manner prescribed by the Committee, direct that the total of the Contributions allocable to his Pre-Tax and After-Tax Contribution Accounts, Employer Contribution Account, Profit Sharing Plan Account and Rollover Account, if any, and the earnings and accretions thereon, be invested in such percentages (in increments of ten percent (10%) of the total of all Accounts) as he may designate among the Investment Funds. In the event a Member fails to direct the manner of investing his Accounts as provided herein, his Accounts shall be invested only in the Money Market Fund.

9.4 Change of Investment Directions: Each Member may, in the manner prescribed by the Committee and subject to any restrictions or conditions which may be established by the Committee, authorize the transfer of existing account balances twelve (12) times each Plan Year

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among the available Investment Funds (in ten percent (10%) increments). Notwithstanding the foregoing, a Member may authorize the transfer of his existing account balances to the Money Market Fund at any time, in a manner prescribed by the Committee and subject to the Committee’s consent and any other restrictions or conditions which may be established by the Committee.

Each Member may, in a form and manner prescribed by the Committee and subject to any restrictions or conditions which may be established by the Committee, direct that the investment of his future Pre-Tax Contributions, After-Tax Contributions and Employer Contributions be changed from one Investment Fund to another.

9.5 Benefits Paid Solely from Trust Fund: All of the benefits provided to be paid under Article VIII shall be paid by the Trustee out of the Trust Fund to be administered under such Trust Agreement. No Fiduciary shall be responsible or liable in any manner for payment of any such benefits, and all Members hereunder shall look solely to such 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.

9.6 Committee Directions to Trustee: The Trustee shall make only such distributions and payments out of the Trust Fund as may be directed by the Committee. The Trustee shall not be required to determine or make any investigation to determine the identity or mailing address of any person entitled to any distributions and payments out of the Trust Fund and shall have discharged its obligation in that respect when it shall have sent certificates and checks or other papers by ordinary mail to such persons and addresses as may be certified to it by the Committee.

9.7 Authority to Designate Investment Manager: The Committee may appoint an investment manager or managers to manage (including the power to acquire and dispose of) any assets of the Trust Fund in accordance with the terms of the Trust Agreement and ERISA.

9.8 Liquidation of Cabot MicroElectronics Stock: Any Cabot MicroElectronics Stock received by the Plan on behalf of a Member shall be liquidated as soon as practicable as directed by the Committee, and such proceeds shall be invested proportionately according to the existing investment elections of the Members at the time of the liquidation.

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ARTICLE X

ADOPTION OF PLAN BY OTHER ORGANIZATIONS;

SEPARATION OF THE TRUST FUND; AMENDMENT

AND TERMINATION OF THE PLAN;

DISCONTINUANCE OF CONTRIBUTIONS TO THE TRUST FUND

10.1 Adoptive Instrument: Any corporation or other organization with employees, now in existence or hereafter formed or acquired which is not already an Employer under this Plan and which is otherwise legally eligible, may, with the approval of the Company by action of the Board of Directors, adopt and become an Employer under this Plan by executing and delivering to the Company and the Trustee an adoptive instrument specifying the classification of its Employees who are to be eligible to participate in the Plan and by agreeing to be bound as an Employer by all the terms of the Plan with respect to its eligible Employees. The adoptive instrument may contain such changes and variations in the terms of the Plan as may be acceptable to the Company. Any such approved organizations which shall adopt this Plan shall designate the Company as its agent to act for it in all transactions affecting the administration of the Plan and shall designate the Committee to act for such Employer and its Members in the same manner in which the Committee may act for the Company and its Members hereunder. The adoptive instrument shall specify the effective date of such adoption of the Plan and shall become, as to such adopting Employer and its Employees, a part of this Plan. Such Employer shall also forthwith obtain a favorable determination letter from the appropriate District Director of the Internal Revenue with respect to its participation in the Plan. 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 under the Plan. Unless otherwise specifically provided, in the event a corporation or organization that has adopted the Plan ceases to be an Affiliate of the Company its participation in the Plan shall terminate.

10.2 Separation of the Trust Fund: A separation of the Trust Fund as to the interest therein of the Members of any particular Employer may be made by an Employer at any time. In such event, the Trustee shall set apart that portion of the Trust Fund which shall be allocated to such Members pursuant to a valuation and allocation of the Trust Fund made in accordance with the procedures set forth in Sections 5.2 and 5.4, but as of the date when such separation of the Trust Fund shall be effective. Such portion 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 such separate trust agreement. Such Employer shall thereupon be deemed to have adopted the Plan as its own separate plan, and shall subsequently have all such powers of amendment or modification of such plan as are reserved herein to the Company.

10.3 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 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 10.2.

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10.4 Amendment of the Plan: The Company shall have the right to amend or modify this Plan and (with the consent of the Trustee) the Trust Agreement at any time and from time to time to any extent that it may deem advisable. Any such amendment or modification shall be set out in an instrument in writing duly authorized by the Board of Directors and executed by the Company. No such amendment or modification shall, however, increase the duties or responsibilities of the Trustee without its consent thereto in writing, or have the effect of transferring to or vesting in any Employer any interest or ownership in any properties of the Trust Fund, or of permitting the same to be used for or diverted to purposes other than for the exclusive benefit of the Members and their Beneficiaries. No such amendment shall decrease the Account of any Member or shall decrease any Member’s vested interest in his Account. Notwithstanding anything herein to the contrary, the Plan or the Trust Agreement may be amended in such manner as may be required at any time to make it conform to the requirements of the Internal Revenue Code or of any United States statutes with respect to employees’ trusts, or of any amendment thereto, or of any regulations or rulings issued pursuant thereto, and no such amendment shall be considered prejudicial to any then existing rights of any Member or his Beneficiary under the Plan.

10.5 Acceptance or Rejection of Amendment by Employers: The Company shall promptly deliver to each other Employer any amendment to this Plan or the Trust Agreement. Each such Employer will be deemed to have consented to such amendment unless it notifies the Company and the Trustee in writing within thirty (30) days after receipt of the amendment that it does not consent thereto, and requests a separation of its interest in the Trust Fund in accordance with the provisions of Section 10.2, as of the first day of the month following such written notification to the Company and the Trustee.

10.6 Termination of the Plan: In accordance with the procedures set forth in this Section 10.6, the Company or any other Employer may effect a termination of the Plan as to such particular Employer under the following circumstances:

(a) The Plan may be terminated by the delivery to the Trustee of an instrument in writing approved and authorized by the board of directors of such Employer. In such event, termination of the Plan shall be effective as of any subsequent date specified in such instrument.

(b) Except as otherwise provided in Section 10.10, the Plan shall terminate effective at the expiration of sixty (60) days following the merger into another corporation or dissolution of any Employer, or following any final legal adjudication of any Employer as a bankrupt or an insolvent, unless within such time a successor organization approved by the Company shall deliver to the Trustee a written instrument certifying that such organization (i) has become the Employer of more than fifty percent (50%) of those Employees of such Employer who are then Members under this Plan and (ii) has adopted the Plan as to its Employees. In any such event the interest in the Plan of any Member whose employment may not be continued by the successor shall be fully vested as of the date of termination of his Service, and shall be payable in cash or in kind within six (6) months from the date of termination of his Service.

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10.7 Liquidation and Distribution of Trust Fund Upon Termination: In the event a complete termination of the Plan in respect of any Employer shall occur, a separation of the Trust Fund in respect of the affected Members of such Employer shall be made as of the effective date of such termination of the Plan in accordance with the procedure set forth in Section 10.2. Following separation of the Trust Fund in respect of the Members of any Employer as to whom the Plan has been terminated, the assets and properties of the Trust Fund, so set apart, shall be reduced to cash as soon as may be expeditious under the circumstances. Any administrative costs or expenses incurred incident to the final liquidation of such separate trust funds shall be paid by the Employer, except that in the case of bankruptcy or insolvency of such Employer any such costs shall be charged against the Trust Fund. Following such partial reduction of such Trust Fund to cash, the Accounts of the Members shall then be valued as provided in Sections 5.2 and 5.4 and shall be fully vested, whereupon each such Member shall become entitled to receive the entire amount in his Account in cash as directed by the Committee. The terminating Employer shall promptly advise the appropriate District Director of Internal Revenue of such complete or partial termination and shall direct the Trustee to delay the final distribution to its affected Members until the 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.

10.8 Effect of Termination or Discontinuance of Contributions: If any Employer shall terminate the Plan as to its Employees, then all amounts credited to the Accounts of the Members of such Employer with respect to whom the Plan has terminated shall become fully vested and non-forfeitable. If any Employer shall completely discontinue its Contributions to the Trust Fund or suspend its Contributions to the Trust Fund under such circumstances as to constitute a complete discontinuance of Contributions within the meaning of Section 1.401-6(c) of the regulations under the Code, then all amounts credited to the Accounts of the Members of such Employer shall become fully vested and non-forfeitable, and throughout any such period of discontinuance of Contributions by an Employer all other provisions of the Plan shall continue in full force and effect with respect to such Employer other than the provisions for Contributions by such Employer.

10.9 Merger of Plan with Another Plan: In the event of any merger or consolidation of the Plan with, or transfer in whole or in part of the assets and liabilities of the Trust Fund to another trust fund held under, any other plan of deferred compensation maintained or to be established for the benefit of all or some of the Members of this Plan, the assets of the Trust Fund applicable to such Members shall be transferred to the other trust fund only if:

(a) Each Member would (if either this Plan or the other plan then terminated) receive a benefit immediately after the merger, consolidation or transfer which is equal to or greater than the benefit he would have been entitled to receive immediately before the merger, consolidation or transfer (if this Plan had then terminated);

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(b) Resolutions of the board of directors of the Employer under this Plan, or of any new or successor employer of the affected Members, shall authorize such transfer of assets, and, in the case of the new or successor employer of the affected Members, its resolutions shall include an assumption of liabilities with respect to such Members’ inclusion in the new employer’s plan; and

(c) Such other plan and trust are qualified under Sections 401(a) and 501(a) of the Code.

10.10 Consolidation or Merger with Another Employer: Notwithstanding any provision of this Article X to the contrary, upon the consolidation or merger of two or more 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 of the Employers involved, and their shares of the Trust Fund shall, subject to the provisions of Section 10.9, be merged and thereafter be allocable to the surviving Employer or organization for its Employees and their Beneficiaries.

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ARTICLE XI

MISCELLANEOUS PROVISIONS

11.1 Terms of Employment: The adoption and maintenance of the provisions of this Plan shall not be deemed to constitute a contract between any Employer and Employee, or to be a consideration for, or an inducement or condition of, the employment of any person. Nothing herein contained shall be deemed to give to any Employee the right to be retained in the employ of an Employer or to interfere with the right of an Employer to discharge an Employee at any time, nor shall it be deemed to give to an Employer the right to require any Employee to remain in its employ, nor shall it interfere with any Employee’s right to terminate his employment at any time.

11.2 Controlling Law: Subject to the provisions of ERISA, this Plan shall be construed, regulated and administered under the laws of the State of Texas.

11.3 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.

11.4 Non-Alienation of Benefits: 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 Member 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 Administrator under the provisions of the Retirement Equity Act of 1984. To the extent provided under a “qualified domestic relations order,” a former spouse of a Member 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 Member, the Committee may authorize the immediate distribution of the amount assigned to the Member’s former spouse, to the extent permitted by law, from the Member’s Accounts.

11.5 Payments in Satisfaction of Claims of Members: Any payment or distribution to any Member or his legal representative or any 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 Trustee and the Employer. The Trustee may require that any distributee execute and deliver to the Trustee a receipt and a full and complete release as a condition precedent to any payment or distribution under the Plan.

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11.6 Payments Due Minors and Incompetents: If the Committee determines that any person to whom a payment is due hereunder is a minor or is incompetent by reason of physical or mental disability, the Committee shall have the power to cause the payments becoming due such person to be made to another for the benefit of such minor or incompetent, without the Committee or the Trustee being responsible to see to the application of such payment. To the extent permitted by ERISA, payments made pursuant to such power shall operate as a complete discharge of the Committee, the Trustee and the Employer.

11.7 Impossibility of Diversion of Trust Fund: Notwithstanding any provision herein to the contrary, no part of the corpus or the income of the Trust Fund shall ever be used for or diverted to purposes other than for the exclusive benefit of the Member or their Beneficiaries or for the payment of expenses of the Plan. No part of the Trust Fund shall ever directly or indirectly revert to any Employer.

11.8 Evidence Furnished Conclusive: The Employer, the Committee and any person involved in the administration of the Plan or management of the Trust Fund shall be entitled to rely upon any certification, statement, or representation made or evidence furnished by a Member or Beneficiary with respect to 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 Member or Beneficiary but not upon the Employer, the Member or any other person involved in the administration of the Plan or management of the Trust Fund. 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 Member or Beneficiary from the duty of submitting satisfactory proof of such fact.

11.9 Copy Available to Members: A copy of the Plan, and of any and all future amendments thereto, shall be provided to the Committee and shall be available to Members and, in the event of the death of a Member, to his Beneficiary, for inspection at the offices of his Employer during the regular office hours of the Employer.

11.10 Unclaimed Benefits: If at, after or during the time when a benefit hereunder is payable to any Member, Beneficiary or other distributee, the Committee, upon request of the Trustee, or at its own instance, shall mail by registered or certified mail to such Member, Beneficiary or other distributee at his last known address a written demand for his then address or for satisfactory evidence of his continued life, or both, and if such Member, Beneficiary or distributee shall fail to furnish the same to the Committee within two (2) years from the mailing of such demand, then the Committee may, in its sole discretion, determine that such Member, Beneficiary or other distributee has forfeited his right to such benefit and may declare such benefit, or any unpaid portion thereof, terminated as if the death of the distributee (with no surviving Beneficiary) had occurred on the date of the last payment made thereon, or on the date such Member, Beneficiary or 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 Member, Beneficiary or other distributee at any time thereafter. Such reinstatement shall be made out of the funds otherwise available for allocation as Forfeitures for the Plan Year during which such claim was filed with the Committee (as provided in Section 4.8); and, if Forfeitures for the Plan Year are insufficient to reinstate such amounts, the Employer shall make the Employer Minimum Contribution required under Section 4.2 hereof.

11.11 Headings for Convenience Only: The headings and subheadings herein are inserted for convenience of reference only and are not to be used in construing this instrument or any provision thereof.

11.12 Successors and Assigns: This agreement shall bind and inure to the benefit of the successors and assigns of the Employers.

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ARTICLE XII

LIMITATION ON BENEFITS

Notwithstanding any provision of this Plan to the contrary, the total Annual Additions made to the Account of a Member for any Plan Year shall be subject to the following limitations:

I. Single Defined Contribution Plan

1. If an Employer does not maintain any other qualified plan, the amount of Annual Additions which may be allocated under this Plan on a Member’s behalf for a Limitation Year shall not exceed the lesser of the Maximum Permissible Amount or any other limitation contained in this Plan.

2. Prior to the determination of the Member’s actual Compensation for a Limitation Year, the Maximum Permissible Amount may be determined on the basis of the Member’s estimated annual Compensation for such Limitation Year. Such estimated annual Compensation shall be determined on a reasonable basis and shall be uniformly determined for all Members similarly situated. Any Employer contributions (including allocation of forfeitures) based on estimated annual Compensation shall be reduced by any Excess Amounts carried over from prior years.

3. As soon as is administratively feasible after the end of the Limitation Year, the Maximum Permissible Amount for such Limitation Year shall be determined on the basis of the Member’s actual Compensation for such Limitation Year.

4. If there is an Excess Amount with respect to a Member for the Limitation Year, any non-deductible voluntary employee contributions, to the extent they would reduce the Excess Amount, will be returned to the Member. Then, Excess Amounts will be treated as a Forfeiture and shall be applied as a credit to subsequent Employer Contributions or reallocated to other Members to the extent such allocations do not exceed the Maximum Permissible Amount all as provided in Section 12(III)(4). Any Excess Amounts that cannot be allocated will be held in a suspense account. All amounts in the suspense account must be allocated and reallocated to the Member’s accounts (subject to the limitations of Section 415) in succeeding Limitation Years before any Employer contribution and non-deductible Employee contribution which would constitute Annual Additions may be made to the Plan.

If a suspense account is in existence at any time during the Limitation Year pursuant to this Section, it will not participate in the allocation of the Trust’s investment gains and losses.

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II. Two or More Defined Contribution Plans

1. If, in addition to this Plan, the Employer maintains any other qualified defined contribution plan, the amount of Annual Additions which may be allocated under this Plan on a Member’s behalf for a Limitation Year, shall not exceed the lesser of:

A. the Maximum Permissible Amount, reduced by the sum of any Annual Additions allocated to the Member’s accounts for the same Limitation Year under such other defined contribution plan or plans; or

B. any other limitation contained in this Plan.

2. Prior to the determination of the Member’s actual Compensation for the Limitation Year, the amount referred to in Section 1(A) above, may be determined on the basis of the Member’s estimated annual Compensation for such Limitation Year. Such estimated annual Compensation shall be determined on a reasonable basis and shall be uniformly determined for all Members similarly situated. Any Employer contribution (including allocation of forfeitures) based on estimated annual Compensation shall be reduced by any Excess Amounts carried over from prior years.

3. As soon as is administratively feasible after the end of the Limitation Year, the amounts referred to in Section 1(A) above shall be determined on the basis of the Member’s actual Compensation for such Limitation Year.

4. If a Member’s Annual Additions under this Plan and all such other defined contribution plans result in an Excess Amount, such Excess Amount shall be deemed to consist of the amounts last allocated.

5. If an Excess Amount was allocated to a Member on an allocation date of this Plan which coincides with an allocation date of another plan, the Excess Amount attributed to this Plan will be the product of:

A. the total Excess Amount allocated as of such date (including any amount which would have been allocated but for the limitations of Section 415 of the Code); times

B. the ratio of (1) the amount allocated to the Member as of such date under this Plan, divided by (2) the total amount allocated as of such date under all qualified defined contribution plans (determined without regard to the limitations of Section 415 of the Code).

6. Any Excess Amounts attributed to this Plan shall be disposed of as provided in Section 12(I)(4).

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III. Definitions

1. Employer: The Company and any other Employer that adopts this Plan. In the case of a group of employers which constitutes a controlled group of corporations (as defined in Code Section 414(b) as modified by Section 415(h)) or which constitutes trades and businesses (whether or not incorporated) which are under common control (as defined in Code Section 414(c) as modified by Section 415(h)) or an affiliated service group (as defined in Code Section 414(m)), all such employers shall be considered a single Employer for purposes of applying the limitations of these sections.

2. Excess Amount: The excess of the Member’s Annual Additions for the Limitation Year over the Maximum Permissible Amount.

3. Limitation Year: The Plan Year.

4. Maximum Permissible Amount: For a Limitation Year, the Maximum Permissible Amount with respect to any Member shall be the lesser of:

A. $35,000 as adjusted by the Secretary of the Treasury or his delegate, or

B. 25% of the Member’s Compensation for the Limitation Year.

5. Compensation: For purposes of determining compliance with the limitations of Code Section 415, Compensation shall mean a Member’s earned income, wages, salaries, fees for professional services and other amounts received for personal services actually rendered in the course of employment with an Employer maintaining the Plan, including, but not limited to, commissions paid salesmen, compensation for services based on a percentage of profits, commissions on insurance premiums, tips and bonuses and excluding the following:

(a) Employer contributions to a plan of a deferred compensation to the extent contributions are not included in gross income of the Employee for the taxable year in which contributed, or on behalf of an employee to a simplified employee pension plan to the extent such contributions are deductible under Code Section 219(b)(2), and any distributions from a plan of deferred compensation whether or not includable in the gross income of the Employee when distributed (however, any amounts received by an Employee pursuant to an unfunded non-qualified plan may be considered as compensation in the year such amounts are included in the gross income of the Employee);

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(b) amounts realized from the exercise of a non-qualified stock option, or when restricted stock (or property) held by an employee becomes freely transferable or is no longer subject to a substantial risk of forfeiture;

(c) amounts realized from the sale, exchange or other disposition of stock acquired under a qualified stock option; and

(d) other amounts which receive special tax benefits, or contributions made by an Employer (whether or not under a salary reduction agreement) towards the purchase of an annuity contract described in Code Section 403(b) (whether or not the contributions are excludable from the gross income of the Employee).

For purposes of applying the limitations in this Article, amounts included as compensation are those actually paid or made available to a Member within the Limitation Year. For Limitation Years beginning after December 31, 1994, Compensation shall be limited to $170,000 (unless adjusted in the same manner as permitted under Code Section 415(d)). Notwithstanding anything to the contrary in this definition, Compensation shall include any and all items which may be included in Compensation under Code Section 415(c)(3), including (i) any elective deferral (as defined in Code Section 402(g)(3) and (ii) any amount which is contributed or deferred by the Employer at the election of the Employee and which is not includible in the gross income of the Employee by reason of Code Section 125, 132(f)(4) or 457.

6. Average Compensation: The average Compensation during a Member’s high three (3) years of service, which period is the three (3) consecutive calendar years (or, the actual number of consecutive years of employment for those employees who are employed for less than three (3) consecutive years with the Employer) during which the Employee had the greatest aggregate Compensation from the Employer.

7. Annual Benefit: A benefit payable annually in the form of a straight life annuity (with no ancillary benefits) under a plan to which Employees do not contribute and under which no rollover contributions are made.

8. Annual Additions: With respect to each Limitation Year, the total of the Employer Contributions, Pre-Tax Contributions, After-Tax Contributions, Forfeitures, and amounts described in Code Sections 415(l) and 419A(d)(2) which are allocated to a Member’s Account.

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ARTICLE XIII

TOP-HEAVY PLAN REQUIREMENTS

13.1 General Rule: For any Plan Year for which this Plan is a Top-Heavy Plan, as defined in Section 13.7, despite any other provisions of this Plan to the contrary, this Plan shall be subject to the provisions of this Article XIII.

13.2 Vesting Provisions: Each Member 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 account under this Plan at least as rapidly as is provided in the following schedule:

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 but less than 6 years	80	%
6 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 Member who had at least three (3) 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 Members, the vested percentage provided in the preceding schedule prior to the date the Plan ceases to be top-heavy shall not be reduced.

13.3 Minimum Contribution Provisions: Each Member who (i) is a Non-Key Employee, as defined in Section 13.7 and (ii) is employed on the last day of the Plan Year will be entitled to have contributions and forfeitures allocated to his account of not less than three percent (3%) (the “Minimum Contribution Percentage”) of the Member’s Compensation. This minimum allocation shall be provided without taking Pre-Tax Contributions into account. A Non-Key Employee may not fail to receive a Minimum Contribution Percentage because of a failure to receive a specified minimum amount of compensation or a failure to make mandatory employee or elective contributions. This Minimum Contribution Percentage will be reduced for any Plan Year to the percentage at which contributions (including Forfeitures) are made or are required to be made under the Plan for the Plan Year for the Key Employee for whom such percentage is the highest for such Plan Year. For this purpose, the percentage with respect to a Key Employee will be determined by dividing the contributions (including Forfeitures) made for such Key Employee by his total compensation (as defined in Section 415 of the Code) not in excess of $200,000 for the Plan Year.

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Such amount will be adjusted in the same manner as the amount set forth in Section 13.4 below.

Contributions considered under the first paragraph of this Section 13.3 will include Employer contributions under this Plan and under all other defined contribution plans required to be included in an Aggregation Group (as defined in Section 13.7 below), but will not include Employer contributions under any plan required to be included in such aggregation group if the plan enables a defined benefit plan required to be included in such group to meet the requirements of the Code prohibiting discrimination as to contributions in favor of employees who are officers, shareholders or the highly compensated or prescribing the minimum participation standards. If the highest rate allocated to a Key Employee for a year in which the Plan is top-heavy is less then three percent (3%), amounts contributed as a result of a salary reduction agreement must be included in determining contributions made on behalf of Key Employees.

Contributions considered under this Section will not include any contributions under the Social Security Act or any other federal or state law.

13.4 Limitation on Compensation: The annual compensation of a Member taken into account under this Article XIII and under Section 1.11 for purposes of computing benefits under this Plan shall not exceed $200,000. 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.

13.5 Coordination with Other Plans: If another defined benefit plan maintained by a Considered Company provides contributions or benefits on behalf of a Member 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 13.3 and 13.4 and to avoid inappropriate omissions or inappropriate duplication of minimum contributions. The determination shall be made by the Committee upon the advice of counsel. In the event a Member 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.

13.6 Distributions to Certain Key Employees: Notwithstanding any other provision of this Plan to the contrary, the entire interest in this Plan of each Member who is a five-percent owner (as described in Section 416(i)(1)(A) 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 Member not later than the first day of April following the calendar year in which such individual attains age 70- ¹/2.

13.7 Determination of Top-Heavy Status: The Plan will be a Top-Heavy Plan for any Plan Year if, as of the Determination Date, the aggregate of the accounts under the Plan (determined as of the Valuation Date) for Members (including former Members) who are Key

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Employees exceeds sixty percent (60%) of the aggregate of the accounts of all Members, excluding former Key Employees, 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 five-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.

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 required to be aggregated and the group of plans permitted to be aggregated. The group of plans 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 the Code, prohibiting discrimination as to contributions or benefits in favor of employees who are officers, shareholders, or the highly compensated or prescribing minimum participation standards.

The group of plans that are permitted to be aggregated (the “permissive aggregation group”) includes the required aggregation group plus one or more plans of a Considered Company that is not part of the required aggregation group and that the Considered Company certifies as a plan within the permissive aggregation group. Such plan or plans may be added to the permissive aggregation group only if, after the addition, the aggregation group as a whole continues not to discriminate as to contributions or benefits in favor of officers, shareholders, or the highly compensated and to meet the minimum participation standards under the Internal Revenue Code of 1986, as amended.

(b) “Determination Date” means for any Plan Year the last day of the immediately preceding Plan Year. However, for the first Plan Year of this Plan, Determination Date means the last day of that Plan Year.

(c) “Key Employee” means any Employee or former Employee under this Plan who, at any time during the Plan Year in question or during any of the four preceding Plan Years, is or was one of the following:

(i) An officer of a Considered Company having an annual compensation greater than fifty percent (50%) of the amount in effect under Section 415(b)(1)(A) of the Code for any such Plan Year. Whether an individual is an officer shall be determined by the Considered Company on the basis of all the facts and circumstances, such as an

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individual’s authority, duties, and term of office, not on the mere fact that the individual has the title of an officer. For any such Plan Year, officers considered to be Key Employees will be no more than the fewer of:

(A) Fifty (50) Employees; or

(B) Ten percent (10%) of the Employees or, if greater than ten percent (10%), three (3) Employees.

For this purpose, the highest paid officers shall be selected.

(ii) One of the ten (10) Employees owning (or considered as owning, within the meaning of the constructive ownership rules of Section 416(i)(1)(B) of the Code) the largest interests in the Considered Company. An Employee who has some ownership interest is considered to be one (1) of the top ten (10) owners unless at least ten (10) other employees own a greater interest than that Employee. However, an Employee will not be considered a top ten (10) owner for a Plan Year if the Employee earns less than the maximum dollar limitation on annual additions to a participant’s account in a defined contribution plan under the Code, as in effect for the calendar year in which the Determination Date falls.

(iii) Any person who owns (or is considered as owning, within the meaning of the constructive ownership rules of Section 416(i)(1)(B) of the Code) more than five percent (5%) of the outstanding stock of a Considered Company or stock possessing more than five percent (5%) of the combined voting power of all stock of the Considered Company.

(iv) Any person who has an annual compensation from the Considered Company of more than One Hundred Fifty Thousand Dollars ($150,000) and who owns (or is considered as owning within the meaning of the constructive ownership rules of Section 416(i)(1)(B) of the Code) more than one percent (1%) of the outstanding stock of the Considered Company or stock possessing more than one percent (1%) of the total combined voting power of all stock of the Considered Company. For purposes of this subsection, compensation means all items includable as compensation for purposes of applying the limitations on annual additions to a Member’s account in a defined contribution plan and the maximum benefit payable under a defined benefit plan under the Code.

For purposes of this subsection (c), a Beneficiary of a Key Employee shall be treated as a Key Employee. For purposes of parts (iii) and (iv), each Considered Company is treated separately in determining ownership percentages; but all such Considered Companies shall be considered a single employer in determining the amount of compensation.

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(d) “Non-Key Employee” means any employee (and any Beneficiary of an employee) who is not a Key Employee.

(e) “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 sixty percent (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 five-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 required aggregation group, each plan in the group will be a Top-Heavy Plan. 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:

(f) 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 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.

(g) In determining the present value of the cumulative accrued benefit (for this purpose using the actuarial assumptions set forth in the applicable pension plan) or the amount of the account of any employee, such present value or account will include the amount in dollar value of the aggregate distributions made to such employee under the applicable plan during the five-year period ending on the Determination Date unless reflected in the value of the accrued benefit or account balance as of the most recent Valuation Date. The amounts will include distributions to employees representing the entire amount credited to their accounts under the applicable plan.

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(h) Further, in making such determination, such present value or such account shall include any rollover contribution (or similar transfer), as follows:

(i) 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.

(ii) 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.

(i) 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 or she 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.

(j) “Valuation Date” means for purposes for 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 twelve-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.

(k) For purposes of this Article XIII, “Compensation” shall have the meaning given to it in Section 12(III)(5).

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ARTICLE XIV

TESTING OF CONTRIBUTIONS

14.1 Definitions: For purposes of this Article XIV, the capitalized words have the following meanings:

A. “After-Tax Contributions” shall mean those contributions defined in Section 1.4.

B. “Compensation” shall mean the Employee’s total Compensation for services rendered to an Employer during the Plan Year and, unless the Committee elects otherwise, the Employee’s Pre-Tax Contributions for the Plan Year and any amounts not currently included in the Employee’s gross income by reason of the application of Section 125 or 132(f)(4) of the Code.

C. “Employer Contributions” shall mean the amounts contributed to the Trust Fund by the Employer pursuant to Section 4.2.

D. “Highly Compensated Employee” shall mean any Employee and any employee of an Affiliate who is a highly compensated employee under Section 414(q) of the Code, including any Employee and any employee of an Affiliate who:

(i) was a 5% owner during the current Plan year or prior Plan Year; or

(ii) received Compensation during the Plan Year (as defined in Section 12(III)(5) in excess of $85,000 or such other dollar amount as may be prescribed by the Secretary of the Treasury or his delegate and, if elected by the Employer, was in the ‘top-paid group’ (the top 20% of payroll) for the Plan Year, excluding Employees described in Code Section 414(p)(8).

In determining an Employee’s status as a Highly Compensated Employee within the meaning of Section 414(q), the entities set forth in Treasury Regulation Section 1.414(q)-1T Q&A-6(a)(1) through (4) must be taken into account as a single employer.

A former Employee shall be treated as a Highly Compensated Employee if (1) such former Employee was a Highly Compensated Employee when such Employee separated from Service, or (2) such former Employee was a Highly Compensated Employee in Service at any time after attaining age 55.

E. “Pre-Tax Contributions” shall mean the amounts contributed to the Trust Fund out of a Member’s Compensation pursuant to Section 4.1(A).

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14.2 Actual Deferral Percentage: The Actual Deferral Percentage for a specified group of Employees for a Plan Year shall be the average of the ratios (calculated separately for each Employee in such group) of:

(a) The amount of Pre-Tax Contributions actually paid to the Plan on behalf of each such Employee for such Plan Year which relate to Compensation that either would have been received by the Employee in such Plan Year (but for the deferral election) or are attributable to services performed by the Employee in the Plan Year and would have been received by the Employee within two and one-half (2- ¹/2) months after the close of the Plan Year (but for the deferral election), over

(b) The Employee’s Compensation for such Plan Year.

The individual ratios and Actual Deferral Percentages shall be calculated to the nearest one-hundredth (1/100) of one percent (1%) of an Employee’s Compensation.

14.3 Actual Deferral Percentage Limits: The Actual Deferral Percentage for the eligible Highly Compensated Employees for any Plan Year shall not exceed the greater of (a) or (b), as follows:

(a) The Actual Deferral Percentage of Compensation for the eligible non-Highly Compensated Employees times 1.25, or

(b) The lesser of (i) the Actual Deferral Percentage of Compensation for the eligible non-Highly Compensated Employees times 2.0 or (ii) the Actual Deferral Percentage of Compensation for the eligible non-Highly Compensated Employees plus two (2) percentage points or such lesser amount as the Secretary of the Treasury shall prescribe to prevent the multiple use of this alternative limitation with respect to any Highly Compensated Employee.

The Actual Deferral Percentage for any Highly Compensated Employee who is eligible to have deferred contributions allocated to his account under one or more plans described in Section 401(k) of the Code that are maintained by an Employer or an Affiliate in addition to this Plan shall be determined as if all such contributions were made to this Plan. For purposes of determining whether the Actual Deferral Percentage limits of Section 14.3 are satisfied, all Pre-Tax Contributions that are made under two or more plans that are aggregated for purposes of Code Section 401(a)(4) or 410(b) (other than Code Section 410(b)(2)(A)(ii)) are to be treated as made under a single plan and if two or more plans are permissively aggregated for purposes of Code Section 401(k) the aggregated plans must also satisfy Code Sections 401(a)(4) and 410(b) as though they were a single plan.

14.4 Reduction of Pre-Tax Contribution Rates by Leveling Method: If on the basis of the Pre-Tax Contribution rates elected by Members for any Plan Year, the Committee determines, in its sole discretion, that neither of the tests contained in (a) or (b) of Section 14.3 will be satisfied, the Committee may reduce the Pre-Tax Contribution rate of any Member who is among the eligible Highly Compensated Employees to the extent necessary to reduce the overall

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Actual Deferral Percentage for eligible Highly Compensated Employees to a level which will satisfy either (a) or (b) of Section 14.3. The reductions in Pre-Tax Contribution rates shall be made in a manner so that the Actual Deferral Percentage of the affected Members who elected the highest Actual Deferral Percentage shall be first lowered to the level of the affected Members who elected the next to the highest Actual Deferral Percentage. If further overall reductions are required to achieve compliance with (a) or (b) of Section 14.3, both of the above-described groups of Members will be lowered to the level of Members with the next highest Actual Deferral Percentage, and so on, until sufficient total reductions in Pre-Tax Contribution rates have occurred to achieve compliance with (a) or (b) of Section 14.3.

14.5 Increase in Pre-Tax Contribution Rates: If a Member’s Pre-Tax Contribution rate is reduced below the level necessary to satisfy either (a) or (b) of Section 14.3 for the Plan Year, such Member may be eligible to increase his Pre-Tax Contribution rate for the remainder of the Plan Year to a level not in excess of that level which will satisfy the greater of (a) or (b) of Section 14.3. Such an increase in the Pre-Tax Contribution rate shall be made by Members on a uniform and non-discriminatory basis, pursuant to such rules and procedures as the Committee may prescribe.

14.6 Excess Pre-Tax Contributions: As soon as possible following the end of the Plan Year, the Committee shall determine whether either of the tests contained in Section 14.3 were satisfied as of the end of the Plan Year, and any excess Pre-Tax Contributions, plus any income and minus any loss attributable thereto, of those Participants who are among the Highly Compensated Employees shall be distributed to such Participants in the manner provided below based on the amount of Pre-Tax Contributions. In addition, the Employer Contribution made with respect to such excess Pre-Tax Contributions shall be forfeited and applied to reduce future Employer Contributions otherwise required under Section 4.2. Such income shall include the allocable gain or loss for the Plan Year only.

The amount of any excess Pre-Tax Contributions to be distributed to a Participant shall be reduced by Excess Deferrals previously distributed to him pursuant to Section 4.1 for the taxable year ending in the same Plan Year. All excess Pre-Tax Contributions shall be returned to the Participants no later than the last day of the following Plan Year. The excess Pre-Tax Contributions, if any, of each Participant who is among the Highly Compensated Employees shall be determined by computing the maximum Actual Deferral Percentage which each such Participant may defer under (a) or (b) of Section 14.3 and then reducing the Actual Deferral Percentage of some or all of such Participants through the distribution of such excess Pre-Tax Contributions, on the basis of the amount of Pre-Tax Contributions of such Participants, as necessary to reduce the overall Actual Deferral Percentage for eligible Participants who are among the Highly Compensated Employees to a level which satisfies either (a) or (b) of Section 14.3, according to the following procedures:

(a) the Pre-Tax Contributions of the Highly Compensated Employee or Employees with the highest dollar amount of Pre-Tax Contributions shall be reduced to equal the dollar amount of the Pre-Tax Contributions of the Highly Compensated Employee or Employees with the next highest dollar amount of Pre-Tax Contributions;

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(b) the reduction amount determined in clause (a) shall be distributed to the Highly Compensated Employee or Employees who had the highest dollar amount of Pre-Tax Contributions prior to such reduction; and

(c) the procedures in clause (a) and (b) shall be repeated until the total excess Pre-Tax Contributions are distributed and compliance is achieved with (a) or (b) of Section 14.3.

If these distributions are made, the Actual Deferral Percentage is treated as meeting the nondiscrimination test of Section 401(k)(3) of the Code regardless of whether the Actual Deferral Percentage, if recalculated after distributions, would satisfy Section 401(k)(3) of the Code. The above procedures are used for purposes of recharacterizing excess Pre-Tax Contributions under Section 401(k)(8)(A)(ii) of the Code. For purposes of Section 401(m)(9) of the Code, if a corrective distribution of excess Pre-Tax Contributions has been made, or a recharacterization has occurred, the Actual Deferral Percentage for Highly Compensated Employees is deemed to be the largest amount permitted under Section 401(k)(3) of the Code.

The income or loss attributable to the Participant’s excess Pre-Tax Contributions for the Plan Year shall be determined by multiplying the income or loss attributable to the Participant’s Pre-Tax Contribution Account balance for the Plan Year by a fraction, the numerator of which is the excess Pre-Tax Contribution and the denominator of which is the Participant’s total Pre-Tax Contribution Account balance. Excess Pre-Tax Contributions shall be treated as Annual Additions under Section 12(III)(8) of the Plan.

14.7 Contribution Percentage: The Contribution Percentage for a specified group of Employees for a Plan Year shall be the average of the ratios (calculated separately for each Employee in such group) of:

(a) The total of the After-Tax Contributions and Employer Contributions (the “Aggregate Contributions”) paid under the Plan on behalf of each Employee for such Plan Year which are made on account of the Employee’s Pre-Tax Contributions for the Plan Year, are allocated to the Employee’s Employer Contribution Account and After-Tax Contribution Account during such Plan Year and are paid to the Trust no later than the end of the next following Plan Year, to

(b) The Employee’s Compensation for such Plan Year.

To the extent permitted by the Code and applicable regulations, the Employer may elect to take into account, in computing the Contribution Percentage, pre-tax contributions made under this Plan or any other plan of the Employer. A Member’s Contribution Percentage shall be determined after determining the Member’s Excess Deferrals, if any, pursuant to Section 4.1, and after determining the Member’s excess Pre-Tax Contributions pursuant to Section 14.6.

14.8 Contribution Percentage Limits: The Contribution Percentage for the eligible Employees for any Plan Year who are Highly Compensated Employees shall not exceed the greater of (a) or (b), as follows:

(a) The Contribution Percentage for the eligible Employees who are not Highly Compensated Employees times 1.25, or

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(b) The lesser of (i) the Contribution Percentage for the eligible Employees who are not Highly Compensated Employees times 2.0 or (ii) the Contribution Percentage for the eligible Employees who are not Highly Compensated Employees plus two (2) percentage points or such lesser amount as the Secretary of the Treasury shall prescribe to prevent the multiple use of this alternative limitation with respect to any Highly Compensated Employee.

The Contribution Percentage for any Highly Compensated Employee for any Plan Year who is eligible to have matching employer contributions made on his behalf or to make after-tax contributions under one or more plans described in Section 401(a) of the Code that are maintained by an Employer or an Affiliate in addition to this Plan shall be determined as if all such contributions were made to this Plan.

In the event that this Plan must be combined with one or more other plans in order to satisfy the requirements of Code Section 410(b), then the Contribution Percentage shall be determined as if all such plans were a single plan.

14.9 Treatment of Excess Aggregate Contributions: If neither of the tests described above in Section 14.8 are satisfied with respect to either Aggregate Contributions, the excess Aggregate Contributions, plus any income and minus any loss attributable thereto, shall be forfeited or, if not forfeitable, shall be distributed no later than the last day of the Plan Year following the Plan Year in which such excess Aggregate Contributions were made. Such income shall include the allocable gain or loss for the Plan Year only. The income or loss attributable to the Participant’s excess Aggregate Contributions for the Plan Year shall be determined by multiplying the income or loss attributable to the Participant’s Account for the Plan Year by a fraction, the numerator of which is the excess Aggregate Contribution, and the denominator of which is the Participant’s total Account balance. Excess Aggregate Contributions shall be treated as Annual Additions under Section 12(III)(8) of the Plan.

The excess Aggregate Contributions, if any, of each Participant who is among the Highly Compensated Employees shall be determined by computing the maximum Contribution Percentage under (a) or (b) of Section 14.8 and then reducing the Contribution Percentage of some or all of such Participants whose Contribution Percentage exceeds the maximum through the distribution or forfeiture of the excess Aggregate Contributions, on the basis of the amount of such excess contributions attributable to such Participants, as necessary to reduce the overall Contribution Percentage for eligible Participants who are among the Highly Compensated Employees to a level which satisfies either (a) or (b) of Section 14.8, according to the following procedures:

(a) the Aggregate Contributions (as applicable) of the Highly Compensated Employee or Employees with the highest dollar amount of such contributions shall be reduced to equal the dollar amount of the Aggregate Contributions of the Highly Compensated Employee or Employees with the next highest dollar amount of such contributions;

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(b) the reduction amount determined in clause (a) shall be forfeited by or, if not forfeitable, distributed to the Highly Compensated Employee or Employees who had the highest dollar amount of Aggregate Contributions prior to such reduction; and

(c) the procedures in clause (a) and (b) shall be repeated until the total excess Aggregate Contributions are forfeited and/or distributed and compliance is achieved with (a) or (b) of Section 14.8.

If these forfeitures and/or distributions are made, the Contribution Percentage is treated as meeting the nondiscrimination test of Section 401(m)(2) of the Code regardless of whether the Contribution Percentage, if recalculated after such forfeitures and/or distributions would satisfy Section 401(m)(2) of the Code. For purposes of Section 401(m)(9) of the Code, if a corrective distribution of excess Aggregate Contributions has been made, the Contribution Percentage for Highly Compensated Employees is deemed to be the largest amount under Section 401(m)(2) of the Code.

For each Participant who is a Highly Compensated Employee, the amount of excess Aggregate Contributions is equal to the total Employer Contributions and After-Tax Contributions on behalf of the Participant (determined prior to the application of this paragraph) minus the amount determined by multiplying the Participant’s actual contribution ratio (determined after application of this paragraph) by his Compensation used in determining such ratio. The individual ratios and Contribution Percentages shall be calculated to the nearest 1/100 of 1% of the Employee’s Compensation, as such term is used in paragraph (b) of Section 14.8.

14.10 Application of Participation and Discrimination Standards: The Plan will use the actual deferral percentage and the actual contribution percentage for Members who are Highly Compensated Employees and non-highly compensated employees for the current Plan Year.

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IN WITNESS WHEREOF, the Company has executed these presents as evidenced by the signatures affixed hereto of its officers hereunto duly authorized, and by its corporate seal being affixed hereto, 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 February, 2002, but effective as of January 1, 2001.

CABOT OIL AND GAS CORPORATION

By

ATTEST:

Secretary

[SEAL]

THE STATE OF TEXAS	§
	§
COUNTY OF HARRIS	§

BEFORE ME, the undersigned authority, on this day personally appeared                                         ,                                          of CABOT OIL AND GAS CORPORATION, known to me to be the person and officer whose name is subscribed to the foregoing instrument, and acknowledged to me that he executed the same as the act of the said CABOT OIL AND GAS CORPORATION, a corporation, and that he was duly authorized to perform the same and that he executed the same as the act and deed of said corporation for the purposes and consideration therein expressed and in the capacity therein stated.

GIVEN UNDER MY HAND AND SEAL OF OFFICE this the      day of                     , 2002.

Notary Public, State of Texas

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APPENDIX A

Vesting of Certain Employees Upon Termination of Employment

The following Employees who, upon termination of employment with the Company, (i) are eligible to receive benefits under the following severance plans and (ii) if required by the applicable severance plan, sign a valid waiver and release shall be fully vested in their benefits under the Plan.

1. Severance Plans 507 through 574

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EX-10.20(A)

Exhibit 10.20(a)

CABOT OIL & GAS CORPORATION

SAVINGS INVESTMENT PLAN

(As Amended and Restated Effective January 1, 2001)

First Amendment

Cabot Oil & Gas Corporation, a Delaware corporation (the “Company”), having established the Cabot Oil & Gas Corporation Savings Investment Plan, as amended and restated January 1, 2001 (the “Plan”), and having reserved the right under Section 10.4 thereof to amend the Plan, does hereby amend the Plan, to make certain law changes, including those which reflect certain provisions of the Economic Growth and Tax Relief Reconciliation Act of 2001 (“EGTRRA”). This Amendment is intended as good faith compliance with the requirements of EGTRRA and is to be construed in accordance with EGTRRA and guidance issued thereunder. This Amendment shall supersede the provisions of the Plan to the extent those provisions are inconsistent with the provisions of this Amendment. Except as otherwise provided, this Amendment shall be effective as of January 1, 2002.

1. The definition of “Compensation” in Section 1.11 of the Plan is hereby amended by adding the following sentence to the end thereof:

“Effective as of January 1, 2002, Compensation taken into account under the Plan for any Member during a Plan Year beginning on or after January 1, 2002 shall not exceed $200,000 (or such other amount provided under Section 401(a)(17) of the Code), as adjusted for cost-of-living increases in accordance with Section 401(a)(17)(B) of the Code.”

2. The definition of “Rollover Amount” in Section 1.37 of the Plan is hereby amended by adding the following paragraph to the end thereof:

“Effective January 1, 2002, “Rollover Amount” may also include a transfer of assets made on or after January 1, 2002, from the following types of plans: (i) a qualified plan described in 403(a) of the Code, including employee after-tax contributions; (ii) a qualified plan described in Section 403(b) of the Code, including employee after-tax contributions; and (iii) 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. The Plan will also accept a transfer of assets made on or after January 1, 2002, from the portion of a distribution from an individual retirement account or annuity described in Section 408(a) or 408(b) of the Code that is eligible to be rolled over and would otherwise be includible in gross income. Notwithstanding the forgoing, no transfer of assets will be accepted if, upon acceptance of such transfer, the Plan would thereafter be required to provide for distributions in the form of life annuities.”

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3. Section 2.15 of the Plan is hereby amended in its entirety to read as follows:

“2.15 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 2.15 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 2.15(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 2.16 hereof, and

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(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 2.15(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.”

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4. Section 2.16 of the Plan is hereby amended in its entirety to read as follows:

“2.16 Claims Review Procedure: Upon the Claims Administrator’s denial, in whole or in part of a benefit applied for under Section 2.15, an Applicant shall have the right by written to appeal such denial as set forth in this Section 2.16. 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 2.16 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 2.16.

(a) Non-Disability Claims – General Rules. If an application filed by the Applicant under Section 2.15(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.

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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 set forth:

(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 2.16(a), in the event that the Committee holds regularly scheduled meetings at least quarterly, the provisions of this Section 2.16(b) will apply and control, to the extent that this Section 2.16(b) is inconsistent with the provisions of Section 2.16(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 2.16(b), notice of the Committee’s final decision shall be furnished to the Applicant in writing, in the manner descried in Section 2.16(a).

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(c) Disability Claims. If an application filed by an Applicant under Section 2.15(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

6

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 2.16(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.”

5. Section 4.1 of the Plan is hereby amended by deleting the phrase “fifteen percent (15%)” in each place it appears in Section 4.1 and replacing each such occurrence with the phrase “twenty-five percent (25%)”.

6. Section 4.1(A) of the Plan is hereby amended by adding the following sentence to the end thereof:

“For Plan Years beginning on or after January 1, 2002, a Member’s Pre-Tax Contributions per Plan Year under this Plan and all other plans, contracts or arrangements of the Employer shall not exceed a maximum dollar limitation provided under Section 402(g) of the Code, as adjusted by the Secretary of the Treasury or his delegate for cost-of-living increases pursuant to Section 402(g) of the Code, except to the extent permitted under Section 4.1(C) of the Plan with respect to Catch-Up Contributions, as defined therein.”

7. Effective July 1, 2002, Section 4.1 of the Plan is hereby amended by adding the following subsection 4.1(C) to the Plan, to read in its entirety as follows:

“C. Catch-Up Contributions: Effective July 1, 2002, each Member who may elect to make Pre-Tax Contributions under Section 4.1(A) of this Plan and

7

who has attained age 50 before the close of the Plan Year shall be eligible to elect to make ‘catch-up contributions’ in accordance with, and subject to the limitations of, of Section 414(v) of the Code (‘Catch-Up Contributions’), in the form and manner prescribed by the Committee. Such Catch-Up Contributions shall not be taken into account for purposes of the provisions of the Plan implementing the required limitations of Sections 402(g) and 415 of the Code. Additionally, such Catch-Up Contributions shall not participate in, or be considered in determining, the amount of Employer Contributions under Section 4.2 of the Plan. The Plan shall not be treated as failing to satisfy the provisions of the Plan implementing the requirements of Sections 401(k)(3), 401(k)(11), 401(k)(12), 410(b), or 416 of the Code, as applicable, by reason of the making of such Catch-Up Contributions.”

8. Section 7.4 of the Plan is hereby amended by adding the following sentence to the end thereof:

“Effective January 1, 2002, subject to the other provisions of this Section 7.4 and this Plan, a termination of Service for purposes of this Section 7.4 shall include a Member’s “severance from employment” under Section 401(k)(2)(B)(i)(I) of the Code, occurring on or after January 1, 2002.”

9. The third paragraph of Section 8.1 of the Plan is hereby amended by adding the following sentence to the end thereof:

“As of April 1, 2003 or, if later, the ninety-first day following delivery of notice to Members describing the elimination from this Plan of payment options as provided under the Profit Sharing Plan and the ESOP, such payment options shall be eliminated under this Plan for distributions to any Member whose Distribution Date is on or after said date.”

10. The first sentence of the fourth paragraph of Section 8.1 of the Plan is hereby amended in its entirety to read as follows:

“If the amount to which a terminated Member is entitled is not more than $5,000, including the balance of such Member’s Rollover Account, such amount shall be paid to the Member as soon as practicable after his Distribution Date; if such amount is in excess of $5,000, the distribution shall be made only if the Member so consents.”

11. Section 8.5(B)(a) of the Plan is hereby amended by adding the following paragraph to the end thereof:

“Effective January 1, 2002, any amount that is distributed on account of hardship shall not be an eligible rollover distribution and the distributee may not elect to have any portion of such a distribution paid directly to an eligible retirement plan. Additionally, effective January 1, 2002, a portion of a distribution shall not fail to be an eligible rollover distribution merely because the portion consists of after-tax employee contributions which are not includible in

8

gross income. However, such portion may be transferred only to an individual retirement account or annuity described in Section 408(a) or (b) of the Code, or to a qualified defined contribution plan described in Section 401(a) or 403(a) of the Code that agrees to separately account for amounts so transferred, including separately accounting for the portion of such distribution which is includible in gross income and the portion of such distribution which is not so includible.”

12. Section 8.5(B)(b) of the Plan is hereby amended in its entirety to read as follows:

“(b) Eligible Retirement Plan: An eligible retirement plan is (i) an individual retirement account described in Section 408(a) 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. However, prior to January 1, 2002, in the case of an eligible rollover distribution to a surviving spouse, an eligible retirement plan is an individual retirement account or individual retirement annuity.”

13. The definition of “Maximum Permissible Amount” in Section 12(III)(4) of the Plan is hereby amended in its entirety to read as follows:

“4. Maximum Permissible Amount: Except to the extent permitted under Section 4.1(C) of the Plan with respect to Catch-Up Contributions and Section 414(v) of the Code, if applicable, for a Limitation Year, the Maximum Permissible Amount with respect to any Member shall be the lesser of:

A. $40,000, as adjusted by the Secretary of the Treasury or his delegate pursuant to Code Section 415(d); or

B. 100% of the Member’s compensation, within the meaning of Section 415(c)(3) of the Code, for the Limitation Year. The compensation limit referred to in this clause (B) shall not apply to any contribution for medical benefits after separation from service (within the meaning of Section 401(h) or Section 419A(f)(2) of the Code) which is otherwise treated as an Annual Addition.

The foregoing notwithstanding, the Maximum Permissible Amount shall not include contributions related to qualified military service under Section 3.12 of the Plan.”

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14. The definition of “Compensation” in Section 12(III)(5) of the Plan is hereby amended by adding the following sentence to the end thereof:

“The foregoing notwithstanding, for purposes of applying the limitations in this Article for Limitation Years beginning on or after January 1, 2002, Compensation shall be limited to $200,000 (or such other amount provided under Section 401(a)(17) of the Code), as adjusted for cost-of-living increases in accordance with Section 401(a)(17)(B) of the Code.”

15. Section 13(III)(8) of the Plan is hereby amended in its entirety to read as follows:

“8. Annual Additions: With respect to each Limitation Year, the total of the Employer Contributions, Pre-Tax Contributions, After-Tax Contributions. Forfeitures, and amounts described in Code Sections 415(l) and 419A(d)(2) which are allocated to a Member’s Account; excluding, however, any Catch-Up Contributions permitted under Section 4.1(C) of the Plan.”

16. The last sentence in the first paragraph of Section 13.3 of the Plan is hereby amended to read as follows:

“For this purpose, the percentage with respect to a Key Employee will be determined by dividing the contributions (including Forfeitures) made for such Key Employee by his total compensation (as defined in Section 415 of the Code) not in excess of $200,000 (or such other amount provided under Code Section 401(a)(17)) for the Plan Year.”

17. The first sentence in Section 13.4 of the Plan is hereby amended to read as follows:

“The annual compensation of a Member taken into account under this Article XIII and under Section 1.11 for purposes of computing benefits under this Plan will not exceed $200,000 (or such other amount provided under Section 401(a)(17) of the Code), as adjusted by the Secretary of the Treasury or his delegate for cost-of-living increases in accordance with Section 401(a)(17)(B) of the Code.”

18. Article XIII of the Plan is hereby amended by adding the following new Section 13.8 to the end thereof:

“13.8. Modification of Top-Heavy Rules:

(a) Effective Date. This Section shall apply for purposes of determining whether the Plan is a top-heavy plan under Section 416(g) of the Code for Plan Years beginning after December 31, 2001, and whether the Plan satisfies the minimum benefits requirements of Section 416(c) of the Code for such years, and, as applicable, amends this Article XIII of the Plan.

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(b) Determination of Top-Heavy Status.

1. ‘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.

2. This subparagraph (2) shall apply for purposes of determining the present values of accrued benefits and the amounts of account balances of Employees as of the Determination Date.

(A) Distributions during year ending on the Determination Date. 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 separation from service, death, or disability, this provision shall be applied by substituting ‘5-year period’ for ‘1-year period.’

(B) Employees not performing services during the year ending on the Determination Date. 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.

(c) Minimum Benefits. Employer matching contributions shall be taken into account for purposes of satisfying the minimum contribution requirements of Section 416(c)(2) of the Code and the Plan. The preceding sentence shall apply with respect to matching contributions under the Plan or, if the Plan provides that the minimum contribution requirement shall be met in another plan, such other plan. Employer

11

matching contributions that are used to satisfy the minimum contribution requirements shall be treated as matching contributions for purposes of the actual contribution percentage test and other requirements of Section 401(m) of the Code.”

19. Article XIV of the Plan is hereby amended by adding the following new Section 14.11 to the end thereof:

“14.11. Multiple Use Test. The multiple use test described in Treasury Regulation Section 1.401(m)- 2 shall not apply for Plan Years beginning after December 31, 2001.”

IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by its duly authorized officer this      day of                     , 2002, but effective as specified herein.

CABOT OIL & GAS CORPORATION

By:

Name:

Title:

12

EX-10.20(B)

Exhibit 10.20(b)

CABOT OIL & GAS CORPORATION

SAVINGS INVESTMENT PLAN

(As Amended and Restated Effective January 1, 2001)

Second Amendment

Cabot Oil & Gas Corporation, a Delaware corporation (the “Company”), having established the Cabot Oil & Gas Corporation Savings Investment Plan, as amended and restated January 1, 2001 and as thereafter amended (the “Plan”), and having reserved the right under Section 10.4 thereof to amend the Plan, does hereby amend the Plan, to make certain law changes regarding required minimum distributions from the Plan. This Amendment shall supersede the provisions of the Plan to the extent those provisions are inconsistent with the provisions of this Amendment. Except as otherwise provided, this Amendment shall be effective as of January 1, 2003.

1. Section 8.3 of the Plan is hereby amended in its entirety to read as follows:

“8.3 Required Minimum Distributions.

(a) General. Notwithstanding any provisions of this Plan to the contrary, for a Member attaining age 70 ¹/2, any benefits to which a Member is entitled shall commence not later than the April 1 following the later of (i) the calendar year in which the Member attains age 70 ¹/2 or (ii) the calendar year in which the Member’s employment terminates (provided, however, that clause (ii) of this sentence shall not apply in the case of a Member who is a 5% owner (as defined in Section 416(i) of the Code) with respect to the Plan Year ending in the calendar year in which such Member attains age 70 ¹/2 (such date the ‘Required Beginning Date’). All distributions required under this Section 8.3 will be made in accordance with the Treasury Regulations under Code Section 401(a)(9) and shall apply for purposes of determining required minimum distributions for calendar years beginning with the 2003 calendar year. The requirements under Code Section 401(a)(9) will take precedence over any inconsistent provisions of the Plans.

(b) Timing and Manner of Distributions. The Member’s entire interest will be distributed, or begin to be distributed, to the Member no later than the Member’s Required Beginning Date. Upon the death of the Member distributions will be made to the Beneficiary in accordance with Section 8.2 of the Plan.

(c) Calculation of Required Minimum Distribution. During the Member’s lifetime, the minimum amount that will be distributed for each Distribution Calendar Year is the quotient obtained by dividing the Member’s Account Balance by the distribution period in the Uniform Lifetime Table set forth in Section 1.401(a)(9)-9 of the Treasury Regulations, using the Member’s age as of the Member’s birthday in the Distribution Calendar Year. Required minimum distributions will be determined beginning with the first Distribution Calendar Year and up to and including the Distribution Calendar Year that includes the Member’s date of death.

1

(d) Required Minimum Distributions After Member’s Death. If the Member dies after his Required Beginning Date his remaining Account balance will be distributed to his Beneficiary in a lump sum payment no later than the December 31 of the year following the year of the Member’s death. If the Member dies before his Required Beginning Date, then payments to the Beneficiary will be made as provided under Section 8.2 of the Plan.

(e) Definitions.

(i) Designated Beneficiary. The individual who is designated as the Beneficiary under Section 8.2 of the Plan and is the Designated Beneficiary under Section 401(a)(9) of the Code and Section 1.401(a)(9)-1, Q&A-4, of the Treasury Regulations.

(ii) Distribution Calendar Year. A calendar year for which a minimum distribution is required. For distributions beginning before the Member’s death, the first Distribution Calendar Year is the calendar year immediately preceding the calendar year which contains the Member’s Required Beginning Date. For distributions beginning after the Member’s death, the first Distribution Calendar Year is the calendar year in which distributions are required to begin under Section 8.3(d). The required minimum distribution for the Member’s first Distribution Calendar Year will be made on or before the Member’s Required Beginning Date. The required minimum distribution for other distribution calendar years, including the required minimum distribution for the Distribution Calendar Year in which the Member’s Required Beginning Date occurs, will be made on or before December 31 of that Distribution Calendar Year.

(iii) Member’s Account Balance. The Account balance as of the last valuation date in the calendar year immediately preceding the Distribution Calendar Year (valuation calendar year) increased by the amount of any contributions made and allocated or forfeitures allocated to the account balance as of dates in the valuation calendar year after the valuation date and decreased by distributions made in the valuation calendar year after the valuation date. The Account balance for the valuation calendar year includes any amounts rolled over or transferred to the Plan either in the valuation calendar year or in the distribution calendar year if distributed or transferred in the valuation calendar year.”

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IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by its duly authorized officer this      day of December, 2003, but effective as specified herein.

CABOT OIL & GAS CORPORATION

By:

Name:

Title:

3

EX-10.20(C)

Exhibit 10.20(c)

CABOT OIL & GAS CORPORATION

SAVINGS INVESTMENT PLAN

(As Amended and Restated Effective January 1, 2001)

Third Amendment

Cabot Oil & Gas Corporation, a Delaware corporation (the “Company”), having established the Cabot Oil & Gas Corporation Savings Investment Plan, as amended and restated January 1, 2001 and as thereafter amended (the “Plan”), and having reserved the right under Section 10.4 thereof to amend the Plan, does hereby amend the Plan, effective as of January 1, 2005, as follows:

1. Section 4.1 of the Plan is hereby amended by deleting the phrase “twenty-five percent (25%)” as it appears in Section 4.1 and replacing each such occurrence with the phrase “fifty percent (50%).”

2. The fourth paragraph of Section 8.1 of the Plan is hereby amended by inserting the following as a new third sentence:

“Notwithstanding the above, in the event of a distribution referenced above which is greater than $1,000 but less than $5,000, if the Member does not elect to have such distribution paid directly to an eligible retirement plan specified by the Member in a direct rollover, or to receive the distribution directly in accordance with the provisions stated elsewhere herein, then the Plan Administrator will pay the distribution in a direct rollover to an individual retirement plan or account designated by the Plan Administrator in its sole discretion.”

IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by its duly authorized officer this      day of                      2005, but effective as specified herein.

CABOT OIL & GAS CORPORATION

By:

Name:

Title:

1

EX-21.1

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.

Cody Texas, LP

Cranberry Pipeline Corporation *

Cabot Petroleum Canada Corporation

Cabot Oil & Gas Holding Company

* Denotes significant subsidiary.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Forms S-3 (Nos. 333-68350 and 333-83819) and Forms S-8 (Nos. 333-37632, 33-35476, 33-71134, 33-53723, 333-92264 and 333-123166) of Cabot Oil & Gas Corporation of our report dated March 6, 2006 relating to the financial statements, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 6, 2006

EX-23.2

Exhibit 23.2

February 20, 2006

Cabot Oil & Gas Corporation

1200 Enclave Parkway

Houston, TX 77077-1607

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

Gentlemen:

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-68350 and 333-83819) and Form S-8 (Nos. 333-37632, 33-35476, 33-71134 , 33-53723, 333-92264 and 333-123166) of Cabot Oil & Gas Corporation of our report dated February 3, 2006, regarding the Cabot Oil & Gas Corporation Proved Reserves and Future Net Revenues as of December 31, 2005, and of references to our firm which report and references are to be included in Form 10-K for the year ended December 31, 2005 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.

Very truly yours,

MILLER AND LENTS, LTD.

/s/ R. W. Frazier

R. W. Frazier

Senior Vice President

EX-31.1

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 annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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 fourth fiscal quarter 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: March 6, 2006
	/s/ Dan O. Dinges
	Dan O. Dinges
	Chairman, President and
	Chief Executive Officer

EX-31.2

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;

2. Based on my knowledge, this annual 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 annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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 fourth fiscal quarter 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: March 6, 2006
	/s/ Scott C. Schroeder
	Scott C. Schroeder
	Vice President and Chief Financial Officer

EX-32.1

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, 2005 (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: March 6, 2006
	/s/ Dan O. Dinges
	Dan O. Dinges
	Chief Executive Officer
	/s/ Scott C. Schroeder
	Scott C. Schroeder
	Chief Financial Officer

EX-99.1

Exhibit 99.1

MILLER AND LENTS, LTD. REVIEW LETTER

February 3, 2006

Cabot Oil & Gas Corporation
1200 Enclave Parkway
Houston, TX 77077-1607
	Re:	Reserves and Future Net Revenues
		As of December 31, 2005
		SEC Price Case

Gentlemen:

At your request, we reviewed the estimates of proved reserves of oil, natural gas liquids, and gas and the future net revenues associated with these reserves that Cabot Oil & Gas Corporation, hereinafter Cabot, attributes to its net interests in oil and gas properties as of December 31, 2005. Cabot’s estimates, shown below, are in accordance with the definitions contained in Securities and Exchange Commission Regulation S-X, Rule 4-10(a) as shown in the Appendix.

Reserves and Future Net Revenues as of December 31, 2005

Reserve Category	Net Reserves		Future Net Revenues
	Liquids, MBbls.	Gas, MMcf	Undiscounted, M$	Discounted at 10% Per Year, M$
Proved Developed	9,127	944,897	7,511,435	3,149,768
Proved Undeveloped	2,336	317,199	2,380,705	852,001
Total Proved	11,463	1,262,096	9,892,140	4,001,769

We made independent estimates for all the proved reserves estimated by Cabot. Based on our investigations and subject to the limitations described hereinafter, it is our judgment that (1) Cabot has an effective system for gathering data and documenting information required to estimate its proved reserves and to project its future net revenues, (2) in making its estimates and projections, Cabot used appropriate engineering, geologic, and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry, and (3) the results of those estimates and projections are, in the aggregate, reasonable.

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, natural gas liquids, and gas as of Cabot’s fiscal year end, December 31, 2005, and are in accordance with Securities and Exchange Commission guidelines. The present value of future net revenues was computed by discounting the future net revenues at 10 per cent per annum. 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 conducting our investigations, we reviewed the pertinent available engineering, geological, and accounting information for each well or designated property to satisfy ourselves that Cabot’s estimates of reserves and future production forecasts and economic projections are, in the aggregate, reasonable. We independently selected a sampling of properties in each region and reviewed the direct operating expenses and product prices used in the economic projections.

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

Reserve estimates were based on decline curve extrapolations, material balance calculations, volumetric calculations, analogies, or combinations of these methods for each well, reservoir, or field. Reserve estimates from volumetric calculations and from analogies are often less certain than reserve estimates based on well performance obtained over a period during which a substantial portion of the reserves were produced.

In making its projections, Cabot estimated yearly well abandonment costs except where salvage values were assumed to offset these expenses. Costs for any possible future environmental claims were not included. 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.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect our informed judgments based on accepted standards of professional investigation but are subject to those generally recognized uncertainties associated with interpretation of geological, geophysical, and engineering information. Government policies and market conditions different from those employed in this study may cause the total quantity of oil, natural gas liquids, or gas to be recovered, actual production rates, prices received, or operating and capital costs to vary from those presented in this report.

In conducting these evaluations, we relied upon production histories, accounting and cost data, and other financial, operating, engineering, and geological data supplied by Cabot. To a lesser extent, nonproprietary data existing in the files of Miller and Lents, Ltd., and data obtained from commercial services were used. We also relied, without independent verification, upon Cabot’s representation of its ownership interests, payout balances and reversionary interests, the current prices, and the transportation fees applicable to each property.

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 an officer of the firm who is a professionally qualified and licensed Professional Engineer in the State of Texas with more than 20 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.
By	/s/ James A. Cole
	James A. Cole
	Senior Consultant
By	/s/ Carl D. Richard
	Carl D. Richard
	Senior Vice President

APPENDIX

Proved Reserves Definitions

In Accordance With

Securities and Exchange Commission Regulation S-X

Proved Oil and Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions.

1. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

2. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project or the operation of an installed program in the reservoirs provides support for the engineering analysis on which the project or program was based.

3. Estimates of proved reserves do not include the following:

a. Oil that may become available from known reservoirs but is classified separately as indicated additional reserves.

b. Crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors.

c. Crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects.

d. Crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite, and other such sources.

Depending upon their status of development, proved reserves are subdivided into proved developed reserves and proved undeveloped reserves.

Proved Developed Oil and Gas Reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. 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 should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Oil and Gas Reserves

Proved undeveloped oil and gas 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 for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved 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.