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, 20042005

Commission file number 1-10447

CABOT OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

1200 Enclave Parkway, Houston, Texas 77077

(Address of principal executive offices including ZIP code)

(281) 589-4600

(Registrant’s telephone number)number, including area code)

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

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.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 an accelerated filera shell company (as defined in Rule 12b-2 of the Act).    Yes  x    No  ¨

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, 2004)2005), as of the last business day of registrant’s most recently completed second fiscal quarter was approximately $1.4$1.7 billion.

As of January 31, 2005,2006, there were 32,414,76048,610,408 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 28, 2005May 4, 2006 are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

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 WestWestern 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 East region,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 West region,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 is comprisedfocused 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 Rocky Mountainshurricanes which included the shutting in and Mid-Continentdeferring of production at the Breton Sound offshore lease, one of our largest areas the Gulf Coast region and Canada.

of offshore oil production.

In 2004,2005, 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. ThisIn the current year, this flexibility should provideallowed 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. At December 31, 2004, our debt to total capital ratio was 37%, down from 43% at the end of 2003. Natural gas production increased to 72.8 Bcf in 2004 from 71.9 Bcf in 2003. This growth was directly related to our 2003 drilling program which focused on natural gas projects. On an equivalent basis, our production level in 2004 was down slightly from 2003. We produced 84.8 Bcfe, or 232.3 Mmcfe per day, this year, as compared to 89.0 Bcfe, or 243.8 Mmcfe per day, in 2003. The growth in natural gas production was offset by the loss of production associated with the late 2003 sale of non-strategic properties and natural decline in oil production in south Louisiana. Our 2004 realized natural gas price was $5.20 per Mcf, compared to a 2003 price of $4.51. Our realized crude oil price was $31.55 per Bbl, compared to a 2003 price of $29.55. Our average hedged prices on natural gas and crude oil for 2005 anticipated production are expected to be higher than comparable prices realized from hedging in 2004. To lock in prices above historical levels for a

A portion of our production as a result of the strong commodity prices, we layered inwas covered by oil and gas hedge instruments throughout 20042005 to cover production in 20042005 and 2005.2006. At December 31, 2004, 44%2005, 33% and 25%26% of our natural gas and crude oil anticipated production, respectively, are hedged for 20052006 through the use of derivatives that qualify for hedge accounting. Including our range swaps, which do not qualify for hedge accounting, 75%As of our crude oil production is hedged for 2005. NoDecember 31, 2005, no derivatives are in place for 2006.2007. Our decision to hedge 20052006 production fits with our risk management strategy and allows the Companyus to lock in the benefit of high commodity prices on a portion of our anticipated production.

Net income of $88.4 million or $2.72 per share exceeded last year by $67.2 million or $2.06 per share. The year over year net income increase was achieved due to higher Our average hedged prices on natural gas revenues from higher commodity prices. Operating Revenues increased by $21.0 million or 4% due to strong commodity prices. Natural gas production revenues increased by $57.1 million over the prior year; this increase was partially offset by a decrease inand crude oil and condensate revenues of $21.0 million and a decreasefor 2006 anticipated production are expected to be higher than comparable prices realized in brokered natural gas revenues of $11.4 million. In addition, operating expenses decreased between 2004 and 2003 as a result of the 2003 non-cash pre-tax impairment charge of $93.8 million. Also contributing to the decrease were lower brokered natural gas cost and lower exploration expense. Net income in 2003 was also reduced by a $6.8 million cumulative effect of accounting change related to SFAS 143.

2005.

For the year ended December 31, 2004,2005, we drilled 256316 gross wells with a success rate of 95% compared to 173256 gross wells with a success rate of 89%95% for the comparable period of 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.

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 compared to $188.2 millionof total capital and exploration spending in 2003.2004. We concentratedremain focused on our 2004strategies of balancing our capital spending program on projects balancinginvestments between acceptable risk and strongest economics, along with the strongest economics.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 MountainMountains areas. In 2004, weWe have continued that practice, to a lesser extent as we increased ourand the allocation of capital expendituresamong regions in the East2005 was similar in responsepercentage to the success ofallocation in 2004, with the 2003 drilling program. The main recipient of these dollars was Canada where we commenced our drilling program with a $16.2 million investment.Gulf Coast region being allocated an additional 12% in capital over the previous year. In 2005,2006, we plan to spend approximately $280$396 million which includes a layer of investment for new projects or property acquisitions that may arise during 2005.

Our proved reserves totaled approximately 1,202 Bcfe at December 31, 2004, of which 94% was natural gas. This reserve level was up slightly from 1,142 Bcfe at December 31, 2003 on the strength of results from our drilling program and the lack of reserve sales 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.

- 3 -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, 2004.2005.

EAST REGION

Our East activities are concentrated primarily in West Virginia, and to a lesser extent in New York.Virginia. In this region, our assets include a large undeveloped 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, for 2004, or 29% of our total 2004 capital spending, and $40.6 million for 2003.spending. For 2005,2006, we have budgeted $75.3$116.1 million for capital and exploration expenditures in the region.

At December 31, 2004,2005, we had 2,5842,745 wells (2,393.3(2,550.2 net), of which 2,4972,657 wells are operated by us. There are multiple producing intervals that include the Big Lime, Weir, Berea and Devonian Shale and Oriskany formations at depths primarily ranging from 1,000 to 9,500 feet. Average net daily production in 20042005 was 53.659.2 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, 2004,2005, we had 550.5637.4 Bcfe of proved reserves (substantially all natural gas) in the East region, constituting 46%48% of our total proved reserves. This region is managed from our office in Charleston, West Virginia.

In 2004,2005, we drilled 171185 wells (167.5(179.8 net) in the East region, of which 166182 wells (163(176.8 net) were development and extension wells. In 2005,2006, we plan to drill approximately 200239 wells.

In 2004,2005, we produced and marketed approximately 8070 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 2004.2005. 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.

- 4 -

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. Cabot Oil & Gas Marketing, our subsidiary, purchases gas from local third-party producers and other suppliers to aggregate larger volumes of gas for resale.

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.Denver, Colorado. At December 31, 2004,2005, we had 426.9432.3 Bcfe of proved reserves (96% natural gas) in the West region, constituting 36%32% of our total proved reserves.

Rocky Mountains

OurActivities in the Rocky Mountains activities are concentrated in the Green River, Wind RiverWashakie and Big Horn Basins in Wyoming and Paradox Basin in Colorado. At December 31, 2004,2005, we had 237.6241.2 Bcfe of proved reserves (95% natural gas) in the Rocky MountainMountains area, 20%or 18% of our total proved reserves. Capital and exploration expenditures in the Rocky Mountains were $41.5$45.4 million for 2004,2005, or 16%11% of our total capital and exploration expenditures, and $22.3$41.5 million for 2003. Spending for 2004 included $30.5 million for drilling activity and $7.5 million of dry hole expense and geophysical and geological procedures.2004. For 2005,2006, we have budgeted $33.6$57.8 million for capital and exploration expenditures in the area.

We had 533576 wells (242.6(252.4 net) in the Rocky Mountains area as of December 31, 2004,2005, of which 282295 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 20042005 was 35.937.3 Mmcfe.

In 2004,2005, we drilled 2949 wells (14.3(16.1 net) in the Rocky Mountains, of which 2645 wells (13.0(13.3 net) were development wells. In 2005,2006, we plan to drill 3042 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 $12.1$23.7 million for 2004,2005, or 5%6% of our total 20042005 capital and exploration expenditures, and $11.2$12.1 million for 2003.2004. For 2005,2006, we have budgeted $8.5$33.1 million for capital and exploration expenditures in the area.

As of December 31, 2004,2005, we had 650680 wells (452.9(471.8 net) in the Mid-Continent area, of which 508523 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 20042005 was 26.529.1 Mmcfe. At December 31, 2004,2005, we had 189.3191.1 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, 16%or 14% of our total proved reserves.

In 2004,2005, we drilled 2134 wells (18.9(21.5 net) in the Mid-Continent, all of which were development and extension wells. In 2005,2006, we plan to drill 1142 wells.

- 5 -

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 2004,2005, 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 $112.6$233.5 million for 2004,2005, or 43%55% of our total capital and exploration expenditures, and $111.6$112.6 million for 2003.2004. During 2005, we spent $72.1 million on proved property acquisitions. For 2005,2006, we have budgeted $105.0$154.4 million of our total budget for capital and exploration expenditures in the region. Our 20052006 Gulf Coast drilling program will continue to emphasize impact exploration opportunities both on and offshore, augmented by development activity in our focus areas of east Texas, north Louisiana and south Texas and throughout coastal Louisiana.

Texas.

In 2004,2005, we drilled 3139 wells (17.6(26.2 net) in the Gulf Coast region, of which 2023 wells (12.4(17.4 net) were development wells. In 20052006, we plan to drill 4255 wells. We had 751788 wells (495.4(515.7 net) in the Gulf Coast region as of December 31, 2004,2005, of which 558582 wells are operated by us. Average daily production in 20042005 was 115.3102.1 Mmcfe, compared to 124.1115.3 Mmcfe in 2003.2004. 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, 2004,2005, we had 217.1240.9 Bcfe of proved reserves (78%(80% natural gas) in the Gulf Coast region, which represented 18% of our total proved reserves.

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 40%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 60%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 2004,2005, we produced and marketed approximately 5,0004,100 barrels of crude oil/condensate per day in the Gulf Coast region at market responsive prices.

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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, 2004,2005, we had 7.920.3 Bcfe of proved reserves (91%(97% natural gas) in the Canada region, constituting less than 1%2% of our total proved reserves.

Capital and exploration expenditures in Canada were $16.2$22.9 million for 2004,2005, or 6%5% of our total capital and exploration expenditures, and $0.8$16.2 million for 2003.2004. For 2005,2006, we have budgeted $16.0$30.7 million for capital and exploration expenditures in the area.

We had 1420 wells (1.5(3.9 net) in the Canada region as of December 31, 2004,2005, of which 38 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 20042005 was 1.03.4 Mmcfe.

In 2004,2005, we drilled 49 wells (1.5(3.5 net) in Canada, of which 35 wells (1.1(1.7 net) were development and extension wells. In 2005,2006, we plan to drill 1013 wells.

In 2004,2005, we produced and marketed approximately 1050 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 20042005 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“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Commodity Price SwapsOperations” and Options“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, 2004.2005.

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 2004.2005. If we had considered the impact of our hedging activities in our proved reserves, there would not have been any significant effect.

There are a number of uncertaintiesFor additional information about the risks inherent in estimating quantitiesour estimates of proved reserves, includingsee “Risk Factors—Reserve estimates depend on many factors beyondassumptions that may prove to be inaccurate. Any material inaccuracies in our control such as commodity pricing. Therefore, the reserve information in this Form 10-K represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different fromor underlying assumptions could cause the quantities and net present value of crude oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Exceptour reserves to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.

- 8 -be overstated” in Item 1A.

Historical Reserves

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

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Volumes and Prices;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.

- 10 -

Leasehold Acreage

Mineral Fee Acreage

- 11 -

Total Net Acreage by Region of Operation

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, 2004.2005. The figures below assume no future successful development or renewal of undeveloped acreage.

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Well Summary

The following table presents our ownership at December 31, 2004,2005, in productive natural gas and oil wells in the Gulf CoastEast region (consisting primarily of various fields located in LouisianaWest Virginia, Virginia and Texas)Ohio), in the West region (consisting of various fields located in Oklahoma, Kansas, Colorado and Wyoming), in the EastGulf Coast region (consisting primarily of various fields located in West Virginia, VirginiaLouisiana and Ohio)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.

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

- 13 -

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 believe that our competitive position in the East region is enhanced by the lack of significant competition from major oil and gas companies. 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. In 2003 and 2002, approximately 11% and 14%, respectively, of our total sales were made to one customer. In 2002, this customer operated certain properties in which we have interests in the Gulf Coast and purchased all of the production from these wells. This customer would resell the natural gas and oil to third parties with whom we would deal directly if the customer either ceased to exist or stopped buying our portion of the production.

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.

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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.

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.

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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. These regulations have generally been approved on judicial review. 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 first such review was completedsecond of these required reviews commenced in December 2000,July 2005, where the FERC concluded thatproposed to continue use of the rate index reasonably reflected actual pipeline costs. Upon judicial review, the pipeline transportation rates established under the index were increased slightly. The next review is scheduled in July 2005. 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

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 relatively new federal regulations, or of the periodic reviewreviews by the FERC of the pipeline index, or the ongoing reviewfinal outcome of the application of the FERC’s new policy on income tax allowance.

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.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, permitspermit 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.

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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

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, 2004,2005, Cabot Oil & Gas had 346354 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.

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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 atwww.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 atwww.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.

ITEM 1A. RISK FACTORS

OtherNatural 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.

Our profitability depends on certainPrices 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:

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:

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:

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:

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

estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and crude oil prices. Please see Items 7that are ultimately recovered, and 7A. 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 including:

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.

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. Any of these events could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. 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 any of these eventsan event not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs

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

Other companies operate some of these insurance policies are somewhat dependent on our historical claims experience and also the areasproperties in which we choosehave an interest. We have limited ability to operate. Duringinfluence or control the past few years,operation or future development of these non-operated properties or the amount of capital expenditures that we have invested a higher percentageare 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 dollarsor 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 the Gulf Coast, where insurance rates are significantly higher thanworld financial markets and could lead to increased volatility in other regions such as the East. At December 31, 2004, we owned or operated approximately 3,300 miles ofprices for natural gas gathering and transmission pipeline systems throughoutoil, 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. As partThe U.S. government has issued public warnings that indicate that energy assets might be specific targets of terrorist organizations. These developments have subjected our normal maintenance program,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 have identified certain segments of our pipelines that we believe may require repair, replacement or additional maintenance,fail to obtain adequate services such as transportation and we schedule this maintenance as appropriate.

processing.

The sale of our oilnatural gas and gasoil production depends on a number of factors beyond our control. The factors includecontrol, including the availability and capacity of transportation and processing facilities. Our failure to access these facilities and 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.

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:

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.

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

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 party todefendant in various legal proceedings arising in the normal course of our business. All known liabilities are fully 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.position or cash flow. Operating results, and cash flow, however, could be significantly impacted in the reporting periods in which such matters are resolved.

Wyoming Royalty Litigation

In June 2000,January 2002, we were sued by two13 overriding royalty owners in Wyoming statefederal district court, for unspecified damages.as reported in previous filings. The plaintiffs requested class certification and alleged that we had improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claimed that we had failed to properly inform the plaintiffs and other similarly situated persons of the deductions taken from royalties. At a mediation held in April 2003, the plaintiffs in this case claimed total damages of $9.5 million plus attorney fees. We settled the case for a total of $2.25 million and the State District Court Judge entered his order approving the settlement in the fourth quarter of 2003. The class included all private fee royalty and overriding royalty owners of the Company in the State of Wyoming except those in the suit discussed below and one owner who opted out of the settlement. It also includes provisions for the method of valuation of gas for royalty payment purposes going forward and for reporting of royalty payments, which should prevent further litigation of these issues by the class members.

In January 2002, 13 overriding royalty owners sued us in Wyoming federal district court. The plaintiffs in the federal case have made the same general claims pertaining to deductions from their overriding royalty as the plaintiffs in the Wyoming state court case but have not askedand claims concerning penalties for class certification.

The federal district court judge certified two questionsimproper reporting. As a result of state law for decisionseveral decisions by the Wyoming State Supreme Court which recently answered both questions.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 Wyoming Supreme Court ruled that certain deductions taken by us fromsettlement included provisions for reporting and payment going forward. In the plaintiffs were not proper and thatthird quarter of 2005, management reversed the statutes of limitations advanced by us are discovery statutes and accordingly do not begin to run until the plaintiffs knew, orreserve we had reason to know, of the violation. We believe we have properly reported to the plaintiffs and, that if werecorded regarding this case, which did not the plaintiffs knew or should have known the reporting was improper and the nature of the deductions, thus triggering the statutes of limitations. We still intend to raise defenses to the alleged failure to report claims. There is also a dispute as to how the interest should be calculated.

The federal judge refused to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statutematerial impact on overriding royalty owner check stubs that had been decided adversely to our position in a state district court letter decision in a separate case. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon recent communication from the plaintiffs, they are now claiming $26.2 million in total damages which consists of $20.3 million for alleged violations of the check stub reporting statute and $5.9 million for all other damages.

In the opinion of our outside counsel, Brown, Drew & Massey, LLP, the likelihood of the plaintiffs recovering $20.3 million for the check stub reporting statute is remote. However, a reserve that management believes is adequate to provide for the check stub reporting statute and all other damages has been established based on management’s estimate at this time of the probable outcome of this case.

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 under the West Virginia Rules of Civil Procedure and allege that we failed to pay royalty based upon the wholesale market value of the gas, produced, that itwe had taken improper deductions from the royalty and failed to properly inform royalty owners of the plaintiffs and other similarly situated persons of deductions taken from the royalty.deductions. The plaintiffs have also claimed that they are entitled to a ¹/8th 1/8th royalty share of the gas sales contract settlement that we reached with Columbia Gas Transmission Corporation in the 1995 Columbia Gas Transmission Corporation bankruptcy proceeding.proceedings.

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Discovery and pleadings necessary to place the class certification issue before the state court have been ongoing. A hearingThe Court entered an order on June 1, 2005 granting the plaintiffs’ motion for class certification was heldcertification. 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 October 20, 2003, and proposed findingsafter December 17, 1991. The Court has postponed the trial date from April 17, 2006, in light of fact and conclusionsa case pending before the West Virginia Supreme Court of Appeals which may decide issues of law were submittedthat may apply to the court on December 5, 2003. A status conference was held with the court and the court advised it intendsissue of deductibility of post-production expenses. We intend to issue a ruling onchallenge the class certification motion. The court was expected to ruleorder by December 2004, and we are still awaitingfiling a decision. Discovery is proceeding onPetition for Writ of Prohibition with the claims pending the ruling on the class certification motion. Discovery is to be completed by April 1, 2005, and the trial is currently scheduled for August 15, 2005. If a class is certified it is expected this trial date will be continued to a later date.West Virginia Supreme Court of Appeals.

The investigation into this claim continues and it is in the discovery phase. We are vigorously defending the case. We have established a reserve that management believes is adequate based on itstheir estimate at this time 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 FirstSecond Supplemental Original Petition on March 17,November 12, 2004 and their SecondThird Supplemental Original Petition on November 12, 2004. The significant change in the second Supplemental Petition is that plaintiffs appear to limit their claim to the mineral estate, rather than making claims to both the surfaceFebruary 22, 2005 (which added Wynn-Crosby 1996, Ltd. and mineral estate. The plaintiffsDominion Oklahoma Texas Exploration & Production, Inc.). Plaintiffs allege that they are the rightful owners of a one-half undivided mineral interest in and to certain lands in Brooks County, Texas. As Cody Energy, LLC, weour subsidiary, acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and we subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. 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. The original trial date of May 19, 2003 was cancelledPlaintiffs claim that they acquired title to the property by adverse possession. Plaintiffs also assert the discovery rule and a new trial date has not been set. Weclaim 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

not had the opportunity to conduct discovery in this matter. We estimate that production revenue from this field since its predecessor, Cody Energy, LLC acquired title and since we acquired its lease is approximately $14.9 million. The$15.7 million, and that the carrying value of this property is approximately $34$33.6 million. Co-defendants Shell Oil Company and Shell Western E&P filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. The original plaintiffs’ attorneys asked permission from the Court to withdraw from the representation. The Court granted that request, and new attorneys for some, but not all of the plaintiffs have recently entered the case. The motion for summary judgment was reset and a hearing was held in December of 2003. We joined in the motion. After a second hearing, the Court denied the motion for summary judgment. The defendants have moved to add parties whose title interests are being challenged by the plaintiffs, and who are therefore necessary to the case, or in the alternative, abate the proceeding until the plaintiffs join all parties whose interests may be affected by plaintiffs’ claims.

Although the investigation into this claim is in its early stages,continues, we intend to vigorously defend the case. Should we receive an adverse ruling in this case, an impairment review would be assessed to ensuredetermine 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 nowe have not established a reserve established for this matter.

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Raymondville Area

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

In December 2003, certain of the co-workingThe working interest owners who elected not to participate in the initial well notified Cody that they believed that they had the right to participate in subsequent wells.wells drilled after the initial well. Cody contends that under the terms of the agreements between the parties, the co-workingworking interest owners that elected not to participate in the initial well in the prospect wereare required to assign their interest in the proposed prospect to those who elected to participate. Alternatively, Cody contends that such owners lost their right to participate in subsequent wells within a 1,200 foot radius of the initial well.

The defendants have filed a counter claim against usthe Company, and one of the defendants has filed a lien against Cody’s interest in the leases in the Raymondville Area. area.

Cody contends that this lien is improper and has sought damages for its filing. Cody is vigorously prosecuting this case which is in its early stage of discovery. No trial date has been set by the court.

Certainsigned 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 Partial Summary Judgment contending that they didReconsideration and Opposition to Proposed Order. The Court has not have adequate notice of the prospect proposal. Cody is contesting this Motion. In addition, in late December 2004, Cody filedyet made a Motion for Final Summary Judgment asking the court to find that, under the terms of the agreements, Cody and the participating working interest owners are entitled to an assignment of the interests of the co-working interest owners who elected not to participate in the prospect. No hearing date has been set by the court.

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.

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 $11.1$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.position or cash flow. Operating results, and cash flow, 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 2004.

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EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information about our executive officers as of February 18, 2005,17, 2006, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.