Back to GetFilings.com

Table of Contents

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.

Table of Contents

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 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.

2

Table of Contents

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.

3

Table of Contents

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.

4

Table of Contents

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.

5

Table of Contents

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.

6

Table of Contents

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.

7

Table of Contents

Historical Reserves

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

8

Table of Contents

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.

9

Table of Contents

Leasehold Acreage

10

Table of Contents

Total Net Acreage by Region of Operation

Well Summary

The following table presents our ownership at December 31, 2003, in natural gas and oil wells in the Gulf Coast region (consisting of various fields located in Louisiana and Texas), in the Western region (consisting of various fields located in Oklahoma, Kansas, Colorado and Wyoming) and in the Eastern region (consisting of various fields located in West Virginia, Virginia and Ohio). 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.

11

Table of Contents

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 Eastern region who do not have similar systems or facilities in place. We also believe that our competitive position in the Eastern 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 Western and Gulf Coast regions.

OTHER BUSINESS MATTERS

Major Customer

In 2003, approximately 11% of our total sales were made to one customer. In 2002, approximately 14% 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. In 2001 we had no sales to any customer that exceeded 10% of our total gross revenues.

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 materially differently by these regulations than others in the industry.

Natural Gas Marketing, Gathering and Transportation

Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938, 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 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 includes 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.

12

Table of Contents

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. Order No. 436 generally required interstate pipelines to become “open access” transporters of natural gas, thereby requiring pipelines to transport gas supplies owned by others in competition with their own supplies. Order No. 636 further required that interstate pipelines cease making “bundled” sales of natural gas, i.e., gas sales at a single price that includes both the cost of the gas and the cost of its delivery, and further required that pipelines “unbundle” their gathering and transmission services. Order No. 637 has implemented additional requirements to increase the transparency of pricing for pipeline services, including requiring pipelines to implement imbalance management services for shippers; restricting the ability of pipelines to impose penalties for imbalances, overruns, and non-compliance with operational flow orders; and implementing a number of new reporting requirements. 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 bulletin boards and electronic data exchange by the pipelines to make available transportation information 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 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 in 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.

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 (or “lighter-handed” regulation) of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, cannot be predicted.

Federal Regulation of Petroleum

Our sales of oil and natural gas liquids are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations

13

Table of Contents

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 has been completed and on December 14, 2000, the FERC reaffirmed the current index. We are not able to predict with certainty the effect upon us of these relatively new federal regulations or of the periodic review by the FERC of the index.

Environmental Regulations

General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating oil and gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us.

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

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

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

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

Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner 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.

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.

14

Table of Contents

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, 2003, Cabot Oil & Gas had 336 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement.

Website Access to Company Reports

We make available free of charge through our website, www.cabotog.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission. Information on our website is not a part of this report.

Other

Our profitability depends on certain factors that are beyond our control, such as natural gas and crude oil prices. Please see Items 7 and 7A. We face a variety of hazards and risks that could cause substantial financial losses. Our business involves a variety of operating risks, including blowouts, cratering, explosions and fires, mechanical problems, uncontrolled flows of oil, natural gas or well fluids, formations with abnormal pressures, pollution and other environmental risks, and natural disasters. 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.

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. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. The costs of these insurance policies are somewhat dependent on our historical claims experience and also the areas in which we choose to operate. During the past few years, we have drilled a higher percentage of our wells in the Gulf Coast, where insurance rates are significantly higher than in other regions such as the East. At December 31, 2003, we owned or operated approximately 3,200 miles of natural gas gathering and transmission pipeline systems throughout the United States. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe may require repair, replacement or additional maintenance, and we schedule this maintenance as appropriate.

The sale of our oil and gas production depends on a number of factors beyond our control. The factors include 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.

ITEM 2. PROPERTIES

See Item 1. Business.

15

Table of Contents

ITEM 3. LEGAL PROCEEDINGS

We are a party to 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. In management’s opinion, final judgments or settlements, if any, which may be awarded in connection with any one or more of these suits and claims would not have a significant impact on the results of operations, financial position or cash flows of any period.

Wyoming Royalty Litigation

In June 2000, we were sued by two overriding royalty owners in Wyoming state court for unspecified damages. The plaintiffs requested class certification under the Wyoming Rules of Civil Procedure and alleged that we improperly deducted costs of production from royalty payments to the plaintiffs and other similarly situated persons. Additionally, the suit claimed that we 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 were recently able to settle the case and the State District Court Judge recently entered his order approving the settlement. The settlement was for a total of $2.25 million. 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 the Company 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 asked for class certification. That case is on hold awaiting a Wyoming Supreme Court decision on two certified questions.

Although management believes that a number of our defenses are supported by Wyoming case law, two letter decisions handed down by state district court judges in other cases do not support certain of the defenses. In one of the cases the case has been settled so no order will be entered. In the other case a generic order has been entered adopting the letter decision by reference. It is not known what effect, if any, the decision, will have on the pending case. In addition, in 2000 a district court judge’s decision supported our defenses, and that decision was recently orally confirmed by another state district court judge. Accordingly, there is a split of authority concerning the interpretation of the reporting penalty provisions of the Wyoming Royalty Payment Act, which will need to be resolved by the Wyoming Supreme Court.

As noted above, the judge agreed to certify two questions of state law for decision by the Wyoming State Supreme Court. The Wyoming State Supreme Court has agreed to decide both questions, and these decisions should dispose of important issues in the pending federal case. The federal judge refused, however, to certify a question relating to the issue of the proper calculation of damages for failure to provide certain information required by statute on overriding royalty owner check stubs that had been decided adversely to our position in the state district court letter decision. After the federal judge’s refusal to certify this issue, the plaintiffs reduced the damages they were claiming. Based upon the plaintiffs expert witness report filed in March 2003, the plaintiffs are now claiming $21 million in total damages which can be broken down into $15.7 million for alleged violations of the check stub reporting statute and the remainder for all other damages. In the opinion of our outside counsel, Brown, Drew & Massey, LLP the likelihood of the plaintiffs recovering the stated damages for violation of the check stub reporting statute is remote.

We are vigorously defending the case. We have a reserve that management believes is adequate to provide for the potential liability based on its estimate of the probable outcome of this case. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact our financial position.

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 we have taken improper

16

Table of Contents

deductions from the royalty and has failed to properly inform the plaintiffs and other similarly situated persons of deductions taken from the royalty. The plaintiffs have also claimed that they are entitled to a 1/8th royalty share of the gas sales contract settlement that we reached with Columbia Gas Transmission Corporation in the 1995 Columbia Gas Transmission Corporation bankruptcy proceeding.

We had removed the lawsuit to federal court; however, in February 2003, we received an order remanding the lawsuit back to state court. Discovery and pleadings necessary to place the class certification issue before the court have been ongoing. A hearing on the plaintiffs’ motion for class certification was held on October 20, 2003, and proposed findings of fact and conclusions of law were submitted to the court on December 5, 2003. The trial is currently scheduled for March 29, 2004. Based on the current status of discovery, the trial date is likely to be continued at a later date.

The investigation into this claim continues and it is in the discovery phase. We are vigorously defending the case. We have reserves we believe are adequate to provide for these potential liabilities based on our estimate of the probable outcome of this matter. Should circumstances change, the potential impact may materially affect quarterly or annual results of operations and cash flows. However, management does not believe it would materially impact our financial position.

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. The 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, the Company acquired certain leases and wells from Wynn-Crosby 1996, Ltd. in 1997 and 1998 and the Company subsequently acquired a 320 acre lease from Hector and Gloria Lopez in 2001. The plaintiffs allege that they are entitled to be declared the rightful owners of an undivided interest in the surface and minerals and all improvements on the lands on which the Company acquired these leases. The plaintiffs also assert claims for trespass to try title, action to remove a cloud on the title, failure to properly account for royalty, fraud, trespass, conversion, all for unspecified actual and exemplary damages. The trial date of May 19, 2003 was cancelled and a new trial date has not been set. 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 $13 million. The carrying value of this property is approximately $35 million. Co-defendants Shell Oil Company and Shell Western E&P have filed a motion for summary judgment seeking dismissal of plaintiffs’ causes of action on multiple grounds. We were in the process of joining in that motion, when the 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 held in December 2003. The Court has permitted plaintiffs additional time to gather more information, and it is anticipated that the court will hold a second hearing on the motion. We have joined in the motion.

Although the investigation into this claim has just begun, we intend to vigorously defend the case. Management cannot currently determine the likelihood or range of any potential outcome.

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 2003.

17

Table of Contents

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information about our executive officers as of February 15, 2004, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.

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

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

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

A. F. (Tony) Pelletier has been Vice President, Regional Manager, Gulf Coast Region since October 2001. Mr. Pelletier joined the Company in April 2001 as Regional Manager, Gulf Coast. Before coming to Cabot, he held positions of increasing responsibility at PetroCorp Incorporated, most recently as Executive Vice President and Chief Operating Officer. Prior to that, he worked at Exxon Company USA in a variety of engineering and supervisory capacities. Mr. Pelletier holds a B.S. in Mechanical Engineering and a master’s in Civil Engineering, both from Texas A&M University. He is a registered professional engineer in the state of Texas.

18

Table of Contents

PART II

The Common Stock is listed and principally traded on the New York Stock Exchange under the ticker symbol “COG.” The following table presents the high and low closing sales prices per share of the Common Stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the Common Stock are also shown.

As of January 30, 2004, there were 761 registered holders of the Common Stock. Shareholders include individuals, brokers, nominees, custodians, trustees, and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms.

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

19

Table of Contents

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

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read Forward-Looking Information on page 30.

We operate in one segment, natural gas and oil exploration and development.

OVERVIEW

Cabot Oil & Gas is a leading independent oil and gas company engaged in the exploration, development and exploitation of natural gas and crude oil from its properties in North America. Our exploration activities are concentrated in areas with known hydrocarbon resources, which are conducive to large, multi-well, repeatable drilling programs and our technical skills. Our program is disciplined and balanced with a focus on achieving strong financial returns.

At Cabot, there are three types of investment alternatives that constantly compete for available capital. These include drilling opportunities, acquisition opportunities and financial opportunities such as debt repayment. Depending on circumstances, we allocate capital among the alternatives based on a rate-of-return approach. Our goal is to invest capital in the highest return opportunities available at any given time.

Our financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. Throughout 2002 and 2003, the NYMEX futures market reported unprecedented natural gas contract prices. Our realized natural gas price was $4.51 per Mcf in 2003. To lock in these high prices, we entered into a series of crude oil and natural gas price collars and swaps. These financial instruments are an integral element of our risk management strategy but prevented us from realizing the full impact of the price environment.

Commodity prices are impacted by many factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas and crude oil prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.

The tables below illustrate how natural gas prices have fluctuated over the course of 2002 and 2003. “Index” represents the Henry Hub index price per Mmbtu. The “2002” and “2003” price is the natural gas price per Mcf realized by us and it includes the impact of the natural gas price collar or swap arrangements:

Prices for crude oil have followed a similar path as the commodity market continued to rise in 2002 and through 2003. The tables below contain the NYMEX average crude oil price (Index) and our realized per Bbl crude oil prices by month for 2002 and 2003.

20

Table of Contents