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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, 2003

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)

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 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  ¨.

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

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, 2003), the last business day of registrant’s most recently completed second fiscal quarter was approximately $889,100,000.

As of January 30, 2004, there were 32,390,158 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 29, 2004 are incorporated by reference into Part III of this report.

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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 for 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 the Texas and Louisiana Gulf Coast, Rocky Mountains, Anadarko Basin, Appalachian Basin and the gas basin of Western Canada. In 2003 we initiated limited operations in Canada. Operationally, we have regional offices located in the Gulf Coast region, the Western region, which is comprised of the Rocky Mountains and Mid-Continent areas, the Eastern region and Canada.

In 2003, energy commodity prices remained strong throughout the year. We leveraged the strong price environment to pay down debt and put Cabot in a financial position to take advantage of attractive acquisition opportunities. At December 31, 2003 our debt to total capital ratio was 43%, down from 51% at the end of 2002. Our production level in 2003 was down slightly from 2002, the year gas and oil production reached the highest annual level in our history. We produced 89.0 Bcfe, or 243.8 Mmcfe per day this year compared to 91.1 Bcfe, or 249.7 Mmcfe per day in 2002. To continue to take advantage of the unusually strong price environment, we layered in oil and gas hedge instruments throughout 2003 to cover production in 2003, 2004 and to a lesser extent 2005. At December 31, 2003, 76% and 72% of our natural gas and crude oil anticipated production, respectively, is hedged for 2004. For 2005 we have hedged 16% of our anticipated natural gas. We do not have any open positions on anticipated 2005 crude oil production. Our decision to hedge this production fits with our risk management strategy and will allow the Company to lock in the benefit of high commodity prices. Our 2003 realized natural gas price was $4.51 per Mcf, compared to a 2002 price of $3.02. Our realized crude oil price was $29.55 per Bbl, compared to a 2002 price of $23.79. Our average hedged prices on natural gas and crude oil for 2004 anticipated production are expected to be higher than comparable prices realized from hedging in 2003.

Net income of $21.1 million or $0.66 per share exceeded last year by $5.0 million or $0.15 per share. Net Operating Revenues increased by $155.6 million or 44% due to strong commodity prices. The year over year increase in net income was achieved despite the non-cash pre-tax impairment charges of $93.8 million and the $6.8 million impact of a cumulative effect of accounting change. The pre-tax non-cash impairment charges consist of $87.9 million related to the liquidation of a limited partnership interest in the Kurten field and $5.9 million related to a field in the East. The cumulative effect of accounting change is related to a $6.8 million charge from the adoption of SFAS 143. These charges were partially offset by a pre-tax gain of $12.2 million recognized primarily on the sale of non-strategic oil and gas properties.

For the year ended December 31, 2003, we drilled 173 gross wells with a success rate of 89% compared to 108 gross wells with a success rate of 93% for the comparable period of the prior year. Our 2003 capital and exploration spending was $188.2 million compared to $126.3 million in 2002. We concentrated our 2003 capital spending program on projects balancing acceptable risk with the strongest economics. In the past, we have used a portion of the cash flow from our long-lived Eastern and Mid-Continent natural gas reserves to fund our exploration and development efforts in the Gulf Coast, Canada and Rocky Mountain areas. In 2003, certain non-strategic assets were sold in the East region. Despite this divestiture, production increased in this region as a result of the drilling program and infrastructure enhancements. Our growth plans for the East region have been redefined for 2004. Accordingly, the East will join the Gulf Coast and Rocky Mountain areas as a focal point of value enhancement efforts through accretive reserve and production growth in 2004. In 2004, we plan to spend $207.4 million and drill 276 gross wells.

Our proved reserves totaled approximately 1,142 Bcfe at December 31, 2003, of which 94% was natural gas. This reserve level was down slightly from 1,171 Bcfe at December 31, 2002 due to 53.4 Bcfe of proved reserve asset sales.

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The following table presents certain information as of December 31, 2003.

GULF COAST REGION

Our exploration, development and production activities in the Gulf Coast region are primarily concentrated in south Louisiana, south Texas and the Gulf of Mexico. A regional office in Houston manages operations. Principal producing intervals are in the Miocene and Frio age formations in Louisiana and the Frio, Vicksburg, and Wilcox formations in Texas at depths ranging from 3,000 to 20,500 feet. Capital and exploration expenditures were $111.6 million for 2003, or 59% of our total 2003 capital and exploration expenditures, and $69.0 million for 2002. For 2004, we have budgeted $87.9 million of our total budget for capital and exploration expenditures in the region. Our 2004 Gulf Coast drilling program will emphasize impact exploration opportunities both on and offshore augmented by development activity in our focus areas of south Texas and coastal Louisiana, including properties acquired in the Cody acquisition.

In 2003, we drilled 41 wells (20.1 net) in the Gulf Coast region, of which 23 wells (11.6 net) were development wells. In 2004 we plan to drill 33 wells. We had 747 wells (504.1 net) in the Gulf Coast region as of December 31, 2003, of which 562 wells are operated by us. Average daily production in 2003 was 124.1 Mmcfe, compared to 127.0 Mmcfe in 2002. 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, 2003, we had 224.6 Bcfe of proved reserves (76% natural gas) in the Gulf Coast region, which represented 20% of our total proved reserves.

Our principal markets for Gulf Coast region natural gas are in the industrialized Gulf Coast area and the northeastern United States. Our marketing subsidiary, Cabot Oil & Gas Marketing Corporation, purchases all the natural gas production from our operated wells in the Gulf Coast region. The marketing subsidiary sells the natural gas to intrastate pipelines, natural gas processors and marketing companies.

Currently, approximately 60% 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 40% 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.

We currently also produce and market approximately 7,100 barrels of crude oil/condensate per day in the Gulf Coast region at market responsive prices.

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WESTERN REGION

Our activities in the Western region are managed by a regional office in Denver. At December 31, 2003, we had 425.7 Bcfe of proved reserves (96% natural gas) in the Western region, constituting 37% of our total proved reserves.

Rocky Mountains

Our Rocky Mountains activities are concentrated in the Green River Basin of Wyoming and Paradox Basin in Colorado. At December 31, 2003 we had 232.8 Bcfe of proved reserves. Capital and exploration expenditures in the Rocky Mountains were $22.3 million for 2003, or 12% of our total capital and exploration expenditures, and $25.9 million for 2002. Current year spending includes $10.9 million for drilling activity and $9.4 million of dry hole expense and geophysical and geological procedures. For 2004, we have budgeted $29.9 million for capital and exploration expenditures in the area.

We had 505 wells (226.1 net) in the Rocky Mountains area as of December 31, 2003, of which 262 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 9,000 to 13,500 feet. Average net daily production in the Rocky Mountains during 2003 was 40.3 Mmcfe.

In 2003, we drilled 19 wells (8.9 net) in the Rocky Mountains, of which 15 wells (6.7 net) were development and extension wells. In 2004, we plan to drill 26 wells.

Mid-Continent

Our Mid-Continent activities are concentrated in the Anadarko Basin in southwestern Kansas, Oklahoma and the panhandle of Texas. Capital and exploration expenditures were $11.2 million for 2003, or 6% of our total 2003 capital and exploration expenditures, and $8.2 million for 2002. For 2004, we have budgeted $17.5 million for capital and exploration expenditures in the area.

As of December 31, 2003, we had 618 wells (430.9 net) in the Mid-Continent area, of which 490 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 1,500 to 14,000 feet. Average net daily production in 2003 was 28.0 Mmcfe. At December 31, 2003, we had 192.9 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, 17% of our total proved reserves.

In 2003, we drilled 15 wells (11.6 net) in the Mid-Continent, all of which were development wells. In 2004, we plan to drill 30 wells.

Our principal markets for Western region natural gas are in the northwestern and midwestern United States. Cabot Oil & Gas Marketing purchases all of our natural gas production in the Western region. The marketing subsidiary sells the 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 Western 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 Western region properties are connected to the majority of the midwestern and northwestern interstate and intrastate pipelines, affording us access to multiple markets.

We currently also produce and market approximately 500 barrels of crude oil/condensate per day in the Western region at market responsive prices.

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EASTERN REGION

Our Eastern activities are concentrated in West Virginia, Ohio and 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 $40.6 million for 2003, or 22% of our total 2003 capital spending, and $22.1 million for 2002. For 2004, we have budgeted $57.9 million for capital and exploration expenditures in the region.

At December 31, 2003, we had 2,418 wells (2,237.4 net), of which 2,334 wells are operated by us. There are multiple producing intervals that include the Big Lime, Weir, Berea, Devonian Shale and Oriskany formations at depths primarily ranging from 1,500 to 9,000 feet. Average net daily production in 2003 was 51.4 Mmcfe. While natural gas production volumes from Eastern reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of Eastern reserves is relatively long. At December 31, 2003, we had 491.8 Bcfe of proved reserves (substantially all natural gas) in the Eastern region, constituting 43% of our total proved reserves. This region is managed from our office in Charleston, West Virginia.

In 2003, we drilled 98 wells (91.4 net) in the Eastern region, of which 92 wells (86.2 net) were development wells. In 2004, we plan to drill 179 wells.

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 2003. 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 3 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 periodically increase 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 Eastern region. The pipeline systems and storage fields are fully integrated with our operations.

In 2003 we purchased 52 miles of pipeline which enables us to deliver gas in a more efficient manner from an existing producing field. Additionally, this acquisition will allow us to deliver gas to certain industrial facilities in West Virginia.

In addition, during most of 2003 we owned and operated two brine treatment plants that processed and treated waste fluid generated during the drilling, completion and production of oil and gas wells. The first plant, near Franklin, Pennsylvania, began operating in 1985 and provided services primarily to other oil and gas producers in southwestern New York, eastern Ohio and western Pennsylvania. In April 1998, we acquired a second brine treatment plant in Indiana, Pennsylvania that had been in existence since 1987. Effective November 1, 2003, we sold this wholly owned subsidiary, Franklin Brine Corporation for $3.4 million in cash, and no longer own or operate any brine treatment facilities.

The principal markets for our Eastern region natural gas are in the northeastern United States. Cabot Oil & Gas Marketing purchases our natural gas production in the Eastern region as well as production from local third-party producers and other suppliers to aggregate larger volumes of natural gas for resale. The marketing subsidiary sells natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system.

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Approximately 65% of our natural gas sales volume in the Eastern region is sold at index-based prices under contracts with a term of one to two years. 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 Eastern production is sold on fixed price contracts that typically renew annually.

RISK MANAGEMENT

From time to time, when we believe that market conditions are favorable, we use certain financial instruments called derivatives to manage price risks associated with our production in all of our regions. While there are many different types of derivatives available, in 2003 we primarily employed natural gas and 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 – Commodity Price Swaps and Options for further discussion concerning our use of derivatives.

RESERVES

Current Reserves

The following table presents our estimated proved reserves at December 31, 2003.

The proved reserve estimates presented here were prepared by our petroleum engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum engineers. 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. 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 2003.

There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond 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 than 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 from the quantities 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. Except 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.

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Historical Reserves

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

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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 oil (including condensate and natural gas liquids), produced natural gas and oil sales prices, and production costs per equivalent.