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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 (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes No o

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. þ

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

The aggregate market value of the voting stock held by non-affiliates of the Registrant as of June 30, 2003, was $12,148,090,102.

On February 29, 2004, 237,953,429 shares of common stock and 1,473,409 exchangeable shares of Devon’s wholly owned subsidiary, Northstar Energy Corporation, were outstanding. Each exchangeable share is exchangeable for one share of Devon common stock.


	“AECO” means the price of gas delivered onto the NOVA Gas Transmission Ltd. System.

	“Bbl” or “Bbls” means barrel or barrels.

	“Bcf” means billion cubic feet.

	“Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.

	“Brent” means pricing point for selling North Sea crude oil.

	“Btu” means British Thermal units, a measure of heating value.

	“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.

	“LIBOR” means London Interbank Offered Rate.

	“MBbls” means thousand barrels.

	“MMBbls” means million barrels.

	“MBoe” means thousand Boe.

	“MMBoe” means million Boe.

	“MMBtu” means million Btu.

	“Mcf” means thousand cubic feet.

	“MMcf” means million cubic feet.

	“NGL” or “NGLs” means natural gas liquids.

	“NYMEX” means New York Mercantile Exchange.

	“Oil” includes crude oil and condensate.

	“Domestic” means the properties of Devon in the onshore continental United States and the offshore Gulf of Mexico.

	“Canada” means the division of Devon encompassing oil and gas properties located in Canada.

	“International” means the division of Devon encompassing oil and gas properties that lie outside the United States and Canada.

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding Devon’s future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or the negative thereof or variations thereon or similar terminology. Although Devon believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from Devon’s expectations (“Cautionary Statements”) include, but are not limited to, Devon’s assumptions about energy markets, production levels, reserve levels, operating results, competitive conditions, technology, the availability of capital resources,

capital expenditure obligations, the supply and demand for oil, natural gas, NGLs and other products or services, the price of oil, natural gas, NGLs and other products or services, currency exchange rates, the weather, inflation, the availability of goods and services, drilling risks, future processing volumes and pipeline throughput, general economic conditions, either internationally or nationally or in the jurisdictions in which Devon or its subsidiaries are doing business, legislative or regulatory changes, including changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations, the securities or capital markets and other factors disclosed under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Item 2. Properties — Proved Reserves and Estimated Future Net Revenue,” “Item 7A. Quantitative and Qualitative Disclosure About Market Risk” and elsewhere in this report. All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. Devon assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.

Devon Energy Corporation, including its subsidiaries, (“Devon”) is an independent energy company engaged primarily in oil and gas exploration, development and production, the acquisition of producing properties, the transportation of oil, gas, and NGLs and the processing of natural gas. Through its predecessors, Devon began operations in 1971 as a privately held company. In 1988, Devon’s common stock began trading publicly on the American Stock Exchange under the symbol “DVN”. In addition, commencing on December 15, 1998, a new class of Devon exchangeable shares began trading on The Toronto Stock Exchange under the symbol “NSX”. These shares are essentially equivalent to Devon common stock. However, because they are issued by Devon’s wholly owned subsidiary, Northstar Energy Corporation (“Northstar”), they qualify as a domestic Canadian investment for Canadian shareholders. They are exchangeable at any time, on a one-for-one basis, for common shares of Devon.

The principal and administrative offices of Devon are located at 20 North Broadway, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).

Devon operates oil and gas properties in the United States, Canada and various regions located outside North America. Devon’s North American properties are concentrated within five geographic areas. Operations in the United States are focused in the Permian Basin, the Mid-Continent, the Rocky Mountains and onshore and offshore Gulf Coast. Canadian operations are focused in the Western Canadian Sedimentary Basin in Alberta and British Columbia. Operations outside North America are located primarily in Azerbaijan, China, Egypt, and areas in West Africa, including Equatorial Guinea, Gabon and Cote d’Ivoire. In addition to its oil and gas operations, Devon has marketing and midstream operations. These include marketing natural gas, crude oil and NGLs, and the construction and operation of pipelines, storage and treating facilities and gas processing plants. (A detailed description of Devon’s significant properties and associated 2003 developments can be found under “Item 2. Properties”).

At December 31, 2003, Devon’s estimated proved reserves were 2,089 MMBoe, of which 58% were natural gas reserves and 42% were oil and NGLs reserves. The present value of pre-tax future net revenues discounted at 10% per annum assuming essentially constant prices (“10% Present Value”) of such reserves was $22.7 billion. After taxes, the present value was $15.9 billion. Devon is one of the largest public independent oil and gas companies based in the United States, as measured by oil and gas reserves.

Devon makes available free of charge on its internet website, www.dvn.com, its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(a) of the Securities Exchange Act of 1934 as soon as reasonably practicable after it electronically files or furnishes them to the Securities Exchange Commission.

Devon’s primary objectives are to build reserves, production, cash flow and earnings per share by (a) acquiring oil and gas properties, (b) exploring for new oil and gas reserves and (c) optimizing production and value from existing oil and gas properties. Devon’s management seeks to achieve these objectives by (a) concentrating its properties in core areas to achieve economies of scale, (b) acquiring and developing high profit margin properties, (c) continually disposing of marginal and non-strategic properties, (d) balancing reserves between oil and gas, (e) maintaining a high degree of financial flexibility, and (f) enhancing the value of Devon’s production and reserves through marketing and midstream activities.

During 1988, Devon expanded its capital base with its first issuance of common stock to the public. This transaction began a substantial expansion program that has continued through the subsequent years. Devon has used a two-pronged strategy of acquiring producing properties and engaging in drilling activities to achieve this expansion. Total proved reserves increased from 8 MMBoe at year-end 1987 (without giving effect to the 1998 and 2000 mergers accounted for as poolings of interests) to 2,089 MMBoe at year-end 2003.

During the same time period, proved reserves have grown from 1.31 Boe per diluted share at year-end 1987 (without giving effect to the 1998 and 2000 poolings) to 9.65 Boe per diluted share at year-end 2003. This represents a compound annual growth rate of 13%. Another measure of value per share is oil and gas production per share. Production increased from 0.18 Boe per diluted share in 1987 (without giving effect to the 1998 and 2000 poolings) to 1.05 Boe per diluted share in 2003, a compound annual growth rate of 12%.

On April 25, 2003, Devon completed its merger with Ocean Energy, Inc. (“Ocean”). In the transaction, Devon issued 0.414 shares of its common stock for each outstanding share of Ocean common stock, or a total of approximately 74 million shares. Also, Devon assumed approximately $1.8 billion of debt from Ocean. The Ocean merger added approximately 554 million Boe to Devon’s proved reserves.

Cash flow from operations was $3.8 billion for 2003. This allowed Devon to fully fund its $2.6 billion of capital expenditures, retire over $500 million in long-term debt and add almost $1 billion to cash on hand. Devon is continuing to accumulate cash with the intent to repay debt as it matures in 2004 and subsequent years.

Devon drilled almost 300 exploration wells and over 1,900 development wells during 2003. See further discussion of Devon’s 2003 exploration and drilling efforts in “Item 2. Properties.”

On January 24, 2002, Devon completed its merger with Mitchell Energy & Development Corp. (“Mitchell”). Under the terms of this merger, Devon issued approximately 30 million shares of Devon common stock and paid $1.6 billion in cash to the Mitchell stockholders. The cash portion of the merger was funded from borrowings under a $3.0 billion senior unsecured term loan credit facility. The Mitchell merger added approximately 404 million Boe to Devon’s proved reserves.

On October 15, 2001, Devon acquired Anderson Exploration Ltd. (“Anderson”) for approximately $3.5 billion in cash. The Anderson acquisition added approximately 534 million Boe to Devon’s proved reserves.

To fund the cash portions of the Mitchell merger and the Anderson acquisition, as well as to pay related transaction costs and retire certain long-term debt assumed from Mitchell and Anderson, Devon entered into long-term debt agreements in October 2001 that totaled $6 billion. Half of this total consisted of $3 billion of notes and debentures issued on October 3, 2001. Of this total, $1.25 billion bears interest at 7.875% and matures in September 2031. The remaining $1.75 billion bears interest at 6.875% and matures in September 2011.

The remaining $3 billion of the $6 billion of long-term debt was borrowed under a credit facility that bears interest at floating rates. As of December 31, 2003, $2.4 billion of the original $3 billion balance had been retired. The primary sources of the repayments were the issuance of $1.5 billion of debt securities, of which $1.3 billion was used to pay down the credit facility with the remainder used to pay down other debt, and $1.4 billion from the sale of certain oil and gas properties, of which $1.1 billion was used to pay down the credit facility. As of December 31, 2003, the balance outstanding under the term loan credit facility was $0.6 billion at an average rate of 2.2%. The terms of this facility require repayment of the remaining debt balance at maturity in October 2006.

Notes 17 and 18 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contains information on Devon’s segments and geographical areas.

Devon is engaged in numerous drilling activities on properties presently owned and intends to drill or develop other properties acquired in the future. Devon’s 2004 drilling activities will be focused in the Rocky Mountains, Permian Basin, Mid-Continent, Gulf of Mexico and onshore Gulf Coast areas in the U.S., the Western Sedimentary basin of Canada and in Brazil, China, Egypt, Russia, Syria and West Africa outside North America.

The following tables set forth the results of Devon’s drilling activity for the past five years.


(1)	Gross wells are the sum of all wells in which Devon owns an interest.

(2)	Net wells are the sum of Devon’s working interests in gross wells.

As of December 31, 2003, Devon was participating in the drilling of 97 gross (61.46 net) wells in the U.S., 41 gross (29.36 net) wells in Canada and 39 gross (12.53 net) wells internationally. Of these wells, through February 1, 2004, 43 gross (30.62 net) wells in the U.S., 36 gross (26.14 net) wells in Canada, and 6 gross (2.23 net) wells internationally had been completed as productive. An additional 3 gross (1.20 net) wells in the U.S. and 1 gross (1.00 net) well in Canada were dry holes. The remaining wells were still in process.

Devon sells its gas production to a variety of customers including pipelines, utilities, gas marketing firms, industrial users and local distribution companies. Existing gathering systems and interstate and intrastate pipelines are used to consummate gas sales and deliveries.

The principal customers for Devon’s crude oil production are refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not conveniently available, crude oil is shipped to storage, refining or pipeline facilities.

The spot market for oil and gas is subject to volatility as supply and demand factors in various regions of North America fluctuate. In addition to fixed price contracts, Devon periodically enters into financial hedging arrangements or firm delivery commitments with a portion of its oil and gas production. These activities are intended to support targeted price levels and to manage Devon’s exposure to price fluctuations. (See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”)

Oil Marketing. Devon’s oil production is sold under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties.

Natural Gas Marketing. Devon’s gas production is also sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary daily, as of February 2004 approximately 78% of Devon’s natural gas production was sold under short-term contracts at variable or market-sensitive prices. These market-sensitive sales are referred to as “spot market” sales. Another 19% were committed under various long-term contracts (one year or more) which dedicate the natural gas to a purchaser for an extended period of time, but still at market sensitive prices. Devon’s remaining gas production was sold under fixed price contracts: 1% under short-term agreements and 2% under long-term contracts.

Typically either the entire contract (in the case of short-term contracts) or the price provisions of the contract (in the case of long-term contracts) are re-negotiated from daily intervals up to one-year

The oil and gas business is highly competitive. Devon encounters competition by major integrated and independent oil and gas companies in acquiring drilling prospects and properties, contracting for drilling equipment and securing trained personnel. Intense competition occurs with respect to marketing, particularly of natural gas. Certain competitors have resources that substantially exceed those of Devon.

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Devon’s operations are subject to various levels of government controls and regulations in the United States, Canada and international locations in which it operates.

In the United States, legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, numerous federal, state and local departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas drilling, pipelines, gas processing plants and production activities, increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, Devon is unable to predict the future cost or impact of complying with such laws and regulations. Devon considers the cost of environmental protection a necessary and manageable part of its business. Devon has been able to plan for and comply with new environmental initiatives without materially altering its operating strategies.

Exploration and Production. Devon’s United States operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells; maintaining bonding requirements in order to drill or operate wells; implementing spill prevention plans; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. Devon’s operations are also subject to various conservation matters, including the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in a unit, and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally limit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas Devon can produce from its wells and to limit the number of wells or the locations at which Devon can drill.

Certain of Devon’s oil and gas leases, including its offshore Gulf of Mexico leases, most of its leases in the San Juan Basin and many of Devon’s leases in southeast New Mexico, Montana and Wyoming, are granted by the federal government and administered by various federal agencies, including the Minerals Management Service of the Department of the Interior (“MMS”). Such leases require compliance with detailed federal regulations and orders which regulate, among other matters, drilling and operations on lands covered by these leases, and calculation and disbursement of royalty payments to the federal government. The MMS has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding and royalty payment obligations for production from federal lands. The Federal Energy Regulatory Commission (“FERC”) also has jurisdiction over certain offshore activities pursuant to the Outer Continental Shelf Lands Act.

Environmental and Occupational Regulations. Various federal, state and local laws and regulations concerning the discharge of incidental materials into the environment, the generation, storage, transportation and disposal of contaminants or otherwise relating to the protection of public health, natural resources, wildlife and the environment, affect Devon’s exploration, development, processing, and production operations and the costs attendant thereto. These laws and regulations increase Devon’s overall operating expenses. Devon maintains levels of insurance customary in the industry to limit its financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, salt water or other substances. However, 100% coverage is not maintained concerning any environmental claim, and no coverage is maintained with respect to any penalty or fine required to be paid by Devon because of its violation of any federal, state or local law. Devon is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. Devon’s unreimbursed expenditures in 2003 concerning such matters were immaterial, but Devon cannot predict with any reasonable degree of certainty its future exposure concerning such matters.

Devon is also subject to laws and regulations concerning occupational safety and health. Due to the continued changes in these laws and regulations, and the judicial construction of same, Devon is unable to predict with any reasonable degree of certainty its future costs of complying with these laws and regulations. Devon considers the cost of safety and health compliance a necessary and manageable part of its business. Devon has been able to plan for and comply with new initiatives without materially altering its operating strategies.

Devon maintains its own internal Environmental, Health and Safety Department. This department is responsible for instituting and maintaining an environmental and safety compliance program for Devon. The program includes field inspections of properties and internal assessments of Devon’s compliance procedures.

Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon’s consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.

Certain of Devon’s subsidiaries acquired in past mergers are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of December 31, 2003, Devon’s consolidated balance sheet included $9 million of non-current accrued liabilities, reflected in “Other liabilities,” related to these and other environmental remediation liabilities.

Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.

The oil and gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect Devon’s Canadian operations in a manner materially different than they would affect other oil and gas companies of similar size. The following are the most important areas of control and regulation.

The North American Free Trade Agreement. The North American Free Trade Agreement (“NAFTA”) which became effective on January 1, 1994 carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed, provided that any export restrictions do not (i) reduce the proportion of energy exported relative to the supply of the energy resource; (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All parties to NAFTA are also prohibited from imposing minimum export or import price requirements.

Exploration and Production. Devon’s Canadian operations are subject to federal and provincial governmental regulation. Such regulation include requiring licenses for the drilling of wells, regulating the location of wells and the method and ability to produce wells, surface usage and the restoration of land upon which wells have been drilled, the plugging and abandoning of wells and the transportation of production from wells. Devon’s Canadian operations are also subject to various conservation regulations, including the regulation of the size of spacing units, the number of wells which may be drilled in a unit, the unitization or pooling of oil and gas properties, the rate of production allowable from oil and gas wells, and the ability to produce oil and gas. In Canada, the effect of such regulation is to limit the amounts of oil and gas Devon can produce from its wells and to limit the number of wells or the locations at which Devon can drill.

Royalties and Incentives. Each province and the federal government of Canada have legislation and regulations governing land tenure, royalties, production rates and taxes, environmental protection and other matters under their respective jurisdictions. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the governments of Canada, Alberta, British Columbia and Saskatchewan have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing the cash flow to the producer.

Pricing and Marketing. The price of oil, natural gas and NGLs sold is determined by negotiation between buyers and sellers. An order from the National Energy Board (“NEB”) is required for oil exports from Canada. Any oil export to be made pursuant to an export contract of longer than one year, in the case of light crude, and two years, in the case of heavy crude, duration (up to 25 years) requires an exporter to obtain an export license from the NEB. The issue of such a license requires the approval of the Government of Canada. Natural gas exported from Canada is also subject to similar regulation by the NEB. Exporters are free to negotiate prices and other terms with purchasers, provided that the export

contracts in excess of two years must continue to meet certain criteria prescribed by the NEB. The governments of Alberta and British Columbia also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

Environmental Regulation. The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties. Devon is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. Devon’s unreimbursed expenditures in 2003 concerning such matters were immaterial, but Devon cannot predict with any reasonable degree of certainty its future exposure concerning such matters.

Kyoto Protocol. In December 2002 the Government of Canada ratified the Kyoto Protocol. This protocol calls for Canada to reduce its greenhouse gas emissions to 6 percent below 1990 levels during the period between 2008 and 2012. The protocol will only become legally binding when it is ratified by at least 55 countries, covering at least 55 percent of the emissions addressed by the protocol. At this time, it is uncertain if the protocol will in fact be ratified. If the protocol becomes legally binding, it is expected to affect the operation of all industries in Canada, including the oil and gas industry. As details of the implementation of emissions reduction initiatives related to this protocol have yet to be announced, the effect on Devon cannot be determined at this time.

Investment Canada Act. The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction requiring such approval.

The oil and gas industry is subject to various types of regulation throughout the world. Legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, government agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas exploration, drilling and production activities, increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, Devon is unable to predict the future cost or impact of complying with such laws and regulations. The following are significant areas of regulation.

Exploration and Production. Devon’s oil and gas concessions and operating licenses or permits are granted by host governments and administered by various foreign government agencies. Such foreign governments require compliance with detailed regulations and orders which regulate, among other matters, seismic, drilling and production operations on areas covered by concessions and permits and calculation and disbursement of royalty payments, taxes and minimum investments to the government.

Regulation includes requiring permits for acquiring seismic data; drilling wells; maintaining bonding requirements in order to drill or operate wells; implementing spill prevention plans; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. Devon’s operations are also subject to regulations which may limit the number of wells or the locations at which Devon can drill.

Production Sharing Contracts. Many of Devon’s international licenses are governed by Production Sharing Contracts (PSC) between the concessionaires and the granting government agency. PSCs are contracts that define and regulate the framework for investments, revenue sharing, and taxation of mineral interests in foreign countries. Unlike most domestic leases, PSCs have defined production terms and time limits of generally 30 years. Many PSCs allow for recovery of investments including carried government percentages. PSCs generally contain sliding scale revenue sharing provisions. For example, at either higher production rates or higher cumulative rates of return, PSCs allow governments to generally retain higher fractions of revenue.

Environmental Regulations. Various government laws and regulations concerning the discharge of incidental materials into the environment, the generation, storage, transportation and disposal of waste or otherwise relating to the protection of public health, natural resources, wildlife and the environment, affect Devon’s exploration, development, processing and production operations and the costs attendant thereto. In general, this consists of preparing Environmental Impact Assessments in order to receive required environmental permits to conduct seismic acquisition, drilling or construction activities. Such regulations also typically include requirements to develop emergency response plans, waste management plans, environmental protection plans and spill contingency plans. In some countries, the application of worldwide standards, such as ISO 14000 governing Environmental Management Systems, are required to be implemented for international oil and gas operations.

As of December 31, 2003, Devon’s staff consisted of 3,924 full-time employees. Devon believes that it has good labor relations with its employees.

Substantially all of Devon’s properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage located in Devon’s core operating areas. These interests entitle Devon to drill for and produce oil, natural gas and NGLs from specific areas. Devon’s interests are mostly in the form of working interests and, to a lesser extent, overriding royalty, volumetric production payments, foreign government concessions, mineral and net profits interests and other forms of direct and indirect ownership in oil and gas properties.

Devon also has certain midstream assets, including natural gas and NGL processing plants and pipeline systems. Devon’s most significant midstream assets are its 3,100 mile Bridgeport pipeline system and 650 MMcf per day Bridgeport gas processing plant located in North Texas.

Set forth below is a summary of the reserves which were evaluated by independent petroleum consultants for each of the years ended 2003, 2002 and 2001.

“Prepared” reserves are those estimates of quantities of reserves which were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of reserves which were estimated by Devon employees and audited by an independent petroleum consultant.

The domestic reserves were evaluated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and Ryder Scott Company, L.P. in each of the years presented. The Canadian reserves were evaluated by the independent petroleum consultants of AJM Petroleum

Devon follows what it believes to be a rational approach to not only recording oil and gas reserves, but also to subjecting these reserves to reviews by independent petroleum consultants. The reserve estimates for all of our Gulf of Mexico and international properties are prepared by an independent petroleum consulting firm every year (excluding 2% of Devon’s 2003 international reserves that were estimated by in-house engineers). In Canada, another independent petroleum consulting firm prepares a rolling one-third of our properties each year so that the reserve estimates for all the Canadian properties are prepared by outside engineers over a three-year cycle.

For the U.S. onshore properties, reserve estimates of individually significant properties are either prepared or audited by an independent petroleum consulting firm, while estimates of minor properties are prepared by in-house engineers. This approach results in independent engineers preparing or auditing over 50% of our U.S. onshore reserves each year.

Over any three-year period, more than 95% of Devon’s company-wide reserve estimates are prepared or audited by an independent petroleum consulting firm. Devon believes this approach provides a high degree of assurance about the validity of our reserve estimates. This is evidenced by the fact that in the past four years, Devon’s annual revisions to its reserve estimates have averaged approximately 2% of the previous year’s estimate.

The following table sets forth Devon’s estimated proved reserves and the related estimated future net revenues, pre-tax 10% Present Value and after-tax standardized measure of discounted future net cash flows as of December 31, 2003. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 18 to Devon’s Consolidated Financial Statements included herein.


(1)	Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of natural gas to oil, which rate is not necessarily indicative of the relationship of gas to oil prices. NGL reserves are converted to Boe on a one-to-one basis with oil. The respective prices of gas and oil are affected by market conditions and other factors in addition to relative energy content.

(2)	Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and development costs. The amounts shown do not give effect to non-property related expenses such as debt service and future income tax expense or to depreciation, depletion and amortization.

These amounts were calculated using prices and costs in effect as of December 31, 2003. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yield average prices over the life of Devon’s properties of $27.55 per Bbl of oil, $5.18 per Mcf of natural gas and $21.22 per Bbl of NGLs. These prices compare to December 31, 2003, New York Mercantile Exchange prices of $32.52 per Bbl for crude oil and $5.97 per MMBtu for natural gas.


(3)	See Note 18 to the consolidated financial statements included in Item 8 of this report.

No estimates of Devon’s proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency since the beginning of the last fiscal year except (i) in filings with the SEC and Canadian Securities Regulators and (ii) in filings with the Department of Energy (“DOE”). Reserve estimates filed by Devon with the SEC and Canadian Securities Regulators correspond with the estimates of Devon reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of Devon’s reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that Devon operates and to exclude all interests in wells that Devon does not operate.

The prices used in calculating the estimated future net revenues attributable to proved reserves do not necessarily reflect market prices for oil, gas and NGL production subsequent to December 31, 2003. There

The process of estimating oil, gas and NGLs reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of, among other things, additional development activity, production history and viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur in the future.

Certain information concerning oil and natural gas production, prices, revenues (net of all royalties, overriding royalties and other third party interests) and operating expenses for the three years ended December 31, 2003, is set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

The following table sets forth Devon’s producing wells as of December 31, 2003:


(1)	Gross wells are the total number of wells in which Devon owns a working interest.

(2)	Net refers to gross wells multiplied by Devon’s fractional working interests therein.

Devon also held numerous overriding royalty interests in oil and gas wells, a portion of which are convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding royalty interests will be included in Devon’s gross and net well count.

The following table sets forth Devon’s developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2003.


(1)	Gross acres are the total number of acres in which Devon owns a working interest.

(2)	Net refers to gross acres multiplied by Devon’s fractional working interests therein.

The day-to-day operation of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. The charges under operating agreements customarily vary with the depth and location of the well being operated.

Devon is the operator of 18,037 of its wells. As operator, Devon receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area. In presenting its financial data, Devon records the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.

Devon’s North American properties are concentrated within five geographic areas. Operations in the United States are focused in the Permian Basin, the Mid-Continent, the Rocky Mountains and onshore and offshore Gulf Coast regions. Canadian operations are focused in the Western Canadian Sedimentary Basin in Alberta and British Columbia. Operations outside North America currently include Azerbaijan, Brazil, China, Egypt, Indonesia, Russia, Syria, and areas in West Africa, including Equatorial Guinea, Gabon, Cote d’Ivoire, Nigeria and Angola. Maintaining a tight geographic focus in selected core areas has allowed Devon to improve operating and capital efficiency.

The following table sets forth proved reserve information on the most significant geographic areas in which Devon’s properties are located as of December 31, 2003.


(1)	Gas reserves are converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of natural gas to oil, which rate is not necessarily indicative of the relationship of gas to oil prices. NGL reserves are converted to Boe on a one-to-one basis with oil. The respective prices of gas and oil are affected by market and other factors in addition to relative energy content.

(2)	Percentage which MMBoe for the basin or region bears to total MMBoe for all proved reserves.


(3)	Determined in accordance with Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities (“SFAS No. 69”), except that no effect is given to future income taxes.

(4)	Percentages which present value for the basin or region bears to total present value for all proved reserves.

(5)	Determined in accordance with SFAS No. 69.

(6)	Canadian dollars converted to U.S. dollars at the rate of $1 Canadian: $0.7738 U.S.

Devon’s Permian Basin assets are located in portions of Southeast New Mexico and West Texas. These assets include conventional oil and gas properties from a wide variety of geologic formations and productive depths. The Permian Basin represented 8% of Devon’s proved reserves at December 31, 2003.

Devon’s leasehold position in Southeast New Mexico encompasses more than 102,000 acres of developed lands and 237,000 acres of undeveloped land and minerals. Historically, Devon has been a very active operator in this area developing gas from the high productivity Morrow formation and oil in the lower risk Delaware formation.

In the West Texas area of the Permian Basin, Devon maintains a base of oil production with long-life reserves. Many of these reserves are from both operated and non-operated positions in large enhanced oil recovery units such as the Wasson ODC Unit, the Willard Unit, the Reeves Unit, the North Welch Unit and the Anton Irish (Clearfork) Unit. These oil-producing units often exhibit low decline rates. Devon also owns a significant acreage position in West Texas with over 194,000 acres of developed lands and over 224,000 acres of undeveloped land and minerals at December 31, 2003.

The Mid-Continent region includes portions of Texas, Oklahoma and Kansas. These areas encompass a wide variety of geologic formations and productive depths and produce both oil and natural gas. Devon’s Mid-Continent production has historically come from conventional oil and gas properties. However, the Barnett Shale, acquired in our 2002 merger with Mitchell Energy, is a non-conventional gas resource. The Mid-Continent region represented 19% of Devon’s proved reserves at December 31, 2003. Approximately 76% of Devon’s proved reserves in the Mid-Continent area are in the Barnett Shale.

The Barnett Shale, Devon’s largest producing field, is known as a tight gas formation. This means that, in its natural state, the formation is resistant to the production of natural gas. Mitchell spent decades understanding how to efficiently develop and produce this gas. The resulting technology has yielded a low-risk and highly profitable natural gas operation. Devon holds 525,000 net acres and nearly 1,600 producing wells in the Barnett Shale. Devon’s average working interest is approximately 95%.

Devon has experienced success extracting gas from the Barnett Shale by using light sand fracturing. Light sand fracturing yields better results than earlier techniques, is less expensive and can be used to complete new wells and to refracture existing wells. Refractured wells often exceed their original flow rates. Devon is also applying horizontal drilling and closer well spacing to further enhance the value of the Barnett Shale.

Devon’s marketing and midstream operations transport and process its Barnett Shale production along with Barnett Shale production from unrelated third parties. The transport system consists of approximately 3,100 miles of pipeline, a 650 MMcf per day gas processing plant, and a 15,000 Bbls per day NGL fractionator.

In 2004, Devon plans to drill a total of 192 new Barnett Shale wells including 94 horizontals and 98 verticals. More than half of the horizontal wells will be drilled outside the core development area in an

effort to further expand the productive area of the field. The Barnett Shale is expected to continue to be an important producing area for Devon for the foreseeable future. Current production from the Barnett Shale is approximately 428 MMcf and 24,100 Bbls of oil and NGLs per day net.

Devon’s operations in the Rocky Mountain region include properties in Wyoming, Montana, Utah, and Northern New Mexico. These assets include conventional oil and gas properties and coalbed methane projects. As of December 31, 2003, the Rocky Mountain region comprised 9% of Devon’s proved reserves.

Approximately 38% of Devon’s proved reserves in the Rocky Mountains are from coalbed methane. Devon began producing coalbed methane in the San Juan Basin of New Mexico in the mid-1980s and began drilling coalbed methane wells in the Powder River Basin of Wyoming in 1998. As of December 31, 2003, Devon has drilled 1,600 coalbed methane wells in the Powder River Basin. Devon’s net coalbed methane gas production from the basin was approximately 88 MMcf per day as of December 31, 2003, and Devon plans to drill 110 new wells in the Powder River Basin in 2004. Current production in the basin is primarily from the Wyodak coal formation. Development of the deeper Big George formation could significantly expand the coalbed methane play into the western portion of the Powder River Basin. The recently approved federal Environmental Impact Statement should facilitate development of the deeper formation. Eighty-five of the wells planned in 2004 target these deeper coals.

Devon’s most significant conventional gas project in the Rocky Mountains region is the Washakie field in Wyoming. Devon is continuing to develop and grow production from this field. In 2003, Devon drilled 38 wells and plans to drill another 40 wells in 2004. Devon has interests in over 200,000 acres. Devon’s current net production from Washakie is approximately 81 MMcf and 1,000 Bbls of oil and NGLs per day.

Devon’s Gulf Coast properties are located in South and East Texas, Louisiana and Mississippi. Most of the wells in the region are completed in conventional sandstone formations. At December 31, 2003, the Gulf Coast accounted for approximately 10% of Devon’s proved reserves.

Devon’s operations in South Texas have focused on exploration in the Edwards, Wilcox and Frio/ Vicksburg formations. Devon has high working interests, up to 100%, in several producing fields.

East Texas is an important conventional gas producing region for Devon. Carthage/ Bethany and Groesbeck are two of the primary producing areas. Wells produce from the Cotton Valley sands, the Travis Peak sands and from shallower sands and carbonates. Devon operates over 1,300 producing wells in East Texas and is currently employing a five-rig drilling and recompletion program to continue low-risk, infill development throughout the area. Devon’s current net production from east Texas is about 187 MMcf and 8,000 Bbls of oil and NGLs per day.

The offshore Gulf of Mexico accounted for 17% of Devon’s 2003 production and 11% of year-end proved reserves. Devon is among the largest independent oil and gas producers in the Gulf of Mexico and operates 450 platforms and caissons. The 2003 merger with Ocean more than tripled Devon’s Gulf reserves. Gulf of Mexico operations are typically differentiated by water depth. The shelf is defined by water depths of 600 feet or less. The deepwater is at depths beyond 600 feet. Devon has active development and drilling programs ongoing in both the shelf and deepwater areas.

In the Ocean merger, Devon acquired interests in the Nansen/ Boomvang complex in the East Breaks area of the deepwater Gulf of Mexico. Devon acquired a 50% working interest in the Nansen field and a 20% interest in the Boomvang field. Ocean established oil and natural gas production at Nansen/ Boomvang in 2002. The Nansen and Boomvang production spars have a combined daily production

Ocean had two additional deepwater development projects under construction in 2003. Redhawk (Garden Banks 876) is expected to commence production in the second half of 2004. Devon has a 50% working interest in Redhawk and estimates net production at about 10,000 Boe per day. Magnolia (Garden Banks 783) is expected to commence production near year-end 2004. Devon has a 25% working interest in this project. Net production is estimated at between 9,000 and 12,000 Boe per day.

In the deepwater of the Gulf of Mexico, Devon drilled two exploratory discovery wells in 2003. The Sturgis well (Atwater Valley 182) found more than 100 net feet of oil pay sands. Sturgis, in 3,700 feet of water, was the second well in Devon’s four-well joint venture with ChevronTexaco. Upon completion of the fourth well, Devon will earn a 25% working interest in 71 deepwater blocks. The fourth well is planned for early 2004.

The second deepwater discovery in 2003 was at St. Malo (Walker Ridge 678). St. Malo, in 6,900 feet of water, encountered more than 450 net feet of oil pay. St. Malo and the previously announced Cascade discovery (Walker Ridge 206) are located in the lower Tertiary trend. Based on early evidence, the lower Tertiary trend may hold significant reserve potential. Devon plans to drill appraisal wells to better define the St. Malo and Cascade discoveries in the first half of 2004. Devon also plans to drill an appraisal well to the Sturgis discovery and additional lower Tertiary exploratory wells during 2004.

In 2003, Devon had a notable shelf discovery on its Grays prospect (Galveston block 424). Three producing wells from this discovery were brought on production in early 2004 at approximately 27 MMcf per day net to Devon’s interest.

The federal government is encouraging Gulf of Mexico operators to drill deep shelf wells, wells drilled on the shelf to a depth greater than 15,000 feet, through a reduced royalty incentive program. Devon plans to drill 10 to 12 deep shelf wells in 2004.

Devon is among the largest independent oil and gas producers in Canada and operates in most of the producing basins in Western Canada. As of December 31, 2003, 28% of Devon’s proved reserves were Canadian. Many of the Canadian basins where Devon operates are accessible for drilling only in the winter when the ground is frozen. Consequently, the winter season, from December through March, is the most active drilling period.

Devon expects to drill about 400 wells in the 2003-2004 winter program and spend $360 million, or nearly half of the full year Canadian capital budget. The winter drilling is focused on three major areas: the Deep Basin, Northeastern British Columbia and the Northern Plains of Alberta. In the Deep Basin, plans call for 106 wells compared with 71 wells last winter. In Northeastern B.C., 93 wells are planned, compared with 73 the previous winter. In the Northern Plains, we expect to drill more than 100 wells this winter, compared with 76 wells a year ago.

The Anderson acquisition in 2001 significantly strengthened Devon’s holdings in the Deep Basin of Western Alberta. Devon had sought for years to obtain a significant acreage position in the Deep Basin, but other operators, including Anderson, already controlled most of the acreage. As a result of the Anderson acquisition, Devon now holds over 800,000 net acres in the Deep Basin. The profitability of Devon’s operations in the Deep Basin is enhanced by its ownership in nine gas processing plants in the area. Devon plans to drill about 193 total wells in the Deep Basin in 2004. Deep Basin reservoirs tend to be rich in liquids, producing up to 100 barrels of NGLs with each MMcf of gas.

In 2002, Devon commenced production from the first of several wells it has drilled in the Grizzly Valley area of the Foothills Region of Northeastern British Columbia. Due to gas pipeline and processing limitations, initial production was limited to about 10 MMcf of gas per day. However, a pipeline extension completed in 2003 allowed Devon to increase production from this area to about 30 MMcf per day. With

Devon also acquired from Anderson approximately 1.5 million net acres in the MacKenzie Delta region and the shallow waters of the Beaufort Sea in Northern Canada. In 2002, a Devon well in the MacKenzie Delta encountered over 110 feet of natural gas pay. Production of this gas awaits an export pipeline to markets in Canada and the United States. Various industry proposals suggest that a pipeline could be built later in the decade.

Devon also drills for and produces “cold-flow” heavy oil in the Lloydminster area of Alberta and Saskatchewan where oil is found in multiple horizons generally at depths of 1,000 to 2,000 feet. In 2003, Devon drilled 263 wells in the Lloydminster area. Average net daily production from the area is approximately 34 MMcf of natural gas and 13,300 Bbls of crude oil.

Devon also owns a 13% working interest in the ConocoPhillips-operated Surmont thermal heavy oil project. Surmont, located north of Jackfish, is designed to produce up to 100,000 barrels of heavy oil per day by 2012. Surmont will also apply SAGD recovery technology.

The Ocean merger more than doubled Devon’s oil and gas reserves outside North America. At December 31, 2003, these international countries accounted for 15% of Devon’s worldwide proved reserves. Most significant was Ocean’s 24% working interest in the Exxon-Mobil-operated Zafiro field, offshore Equatorial Guinea in West Africa. During 2003, production from Zafiro increased significantly due to the addition of the Southern Expansion Area (SEA) in July. Production from the SEA increased total field capacity to 300,000 barrels of oil per day. Devon’s net share increased by about 15,000 barrels to more than 50,000 barrels per day. Devon’s production from Zafiro is expected to decline by about 7,000 barrels per day in the second quarter of 2004. The decline will occur when Devon reaches payout of a portion of its investment in the project and the government’s share of production increases.

Devon experienced another boost in international production in 2003 when its Panyu project offshore China commenced production late in the year. Panyu, in the Pearl River Mouth of the South China Sea, was discovered in 1998. In early 2004, production from the first eight of 27 planned wells reached 50,000 barrels per day. Devon has a 24.5% working interest in the project and expects its share of production to average about 16,000 barrels per day in 2004.

In Azerbaijan in the Caspian Sea, Devon has a 5.6% carried working interest in the Azeri-Chirag-Gunashli, or ACG, oil development project. Devon estimates that the ACG field contains over 4.6 billion barrels of gross proved oil reserves. Oil production from the ACG field will increase dramatically upon completion of the Baku-T’Bilisi-Ceyhan pipeline, which is planned for 2005. Devon’s net share is expected to peak at about 50,000 barrels per day in 2008 or 2009.

Devon also acquired minor producing properties in the Ocean merger in Cote d’Ivoire, Egypt, Indonesia and Russia. Ocean also held exploratory blocks in Angola, Brazil, Equatorial Guinea, Nigeria and Syria. Devon plans to drill exploratory wells in each of the aforementioned countries, except Cote d’Ivoire and Indonesia, in 2004. Devon also produces oil and holds exploratory blocks in Gabon.

Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, other encumbrances. Devon believes that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business.

As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations,

Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.

Devon is a defendant in certain private royalty owner litigation filed in Wyoming regarding deductibility of certain post production costs from royalties payable by Devon. The plaintiffs in these lawsuits propose to expand them into county or state-wide class actions relating specifically to transportation and related costs associated with Devon’s Wyoming gas production. A significant portion of such production is, or will be, transported through facilities owned by Thunder Creek Gas Services, L.L.C., of which Devon owns a 75% interest. Devon believes that it has acted reasonably and paid royalties in good faith and in accordance with its obligations under its oil and gas leases and applicable law, and Devon does not believe that it is subject to material exposure in association with this litigation.

As described more fully in Note 8 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report, Devon has certain exchangeable debentures, with a principal amount totaling $760 million, which are exchangeable at the option of the holders into shares of ChevronTexaco common stock owned by Devon. The debentures were assumed, and the ChevronTexaco common stock was acquired, by Devon in the 1999 PennzEnergy merger.

The Internal Revenue Service is currently examining the 1998 income tax return of PennzEnergy’s predecessor. In draft notices, the IRS has disagreed with certain tax treatments of the exchangeable debentures and similar exchangeable debentures retired in 1998. The IRS has not yet formally asserted a claim for additional taxes for 1998 related to the exchangeable debentures, but Devon believes it is probable that such an assertion will eventually be made.

Based upon the draft notices received from the IRS, Devon estimates that if the IRS formally asserts a claim for additional taxes for 1998 as a result of its current examination, the amount of such claim would approximate $68 million.

Devon does not agree with the positions that have been taken by the IRS in its draft documents, and will vigorously contest any claim of additional taxes. Although the outcome of this matter cannot be predicted with certainty, Devon, after consultation with legal counsel, believes that if the IRS formally asserts a claim for additional taxes regarding the treatment of the exchangeable debentures, Devon would likely prevail. Even if the IRS prevailed in this matter, Devon believes that any related increase in its 1998 taxable income would increase its tax basis in the ChevronTexaco common stock, or produce a similar tax benefit, and would therefore result in offsetting tax deductions in future taxable years upon the disposal of the ChevronTexaco common stock. Therefore, while the payment of any such additional taxes would

If the IRS ultimately prevailed in this matter, any interest owed by Devon on such additional taxes would negatively impact Devon’s operating cash flow and net earnings. However, Devon does not believe that such impact would be material to Devon’s financial condition or results of operations.

Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge as of the date of this report, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.

There were no matters submitted to a vote of security holders during the fourth quarter of 2003.

Devon’s common stock has been traded on the American Stock Exchange (the “AMEX”) since September 29, 1988. Prior to September 29, 1988, Devon’s common stock was privately held. Commencing on December 15, 1998, a new class of Devon exchangeable shares began trading on The Toronto Stock Exchange (“TSE”) under the symbol “NSX”. These shares are essentially equivalent to Devon common stock. However, because they are issued by Devon’s wholly owned subsidiary, Northstar, they qualify as a domestic Canadian investment for Canadian shareholders. They are exchangeable at any time, on a one-for-one basis, for common shares of Devon at the holder’s option.

The following table sets forth the high and low sales prices for Devon common stock and exchangeable shares as reported by the AMEX and TSE for the periods indicated.

Devon commenced the payment of regular quarterly cash dividends on its common stock on June 30, 1993, in the amount of $0.03 per share. Effective December 31, 1996, Devon increased its quarterly dividend payment to $0.05 per share. Effective March 31, 2004, Devon increased its quarterly dividend payment to $0.10 per share.

Devon anticipates continuing to pay regular quarterly dividends in the foreseeable future. Dividends are also paid on the exchangeable shares at the same rate and on the same dates as dividends paid on the common stock.

On February 29, 2004, there were 21,341 holders of record of Devon common stock and 578 holders of record for the exchangeable shares.

The following selected financial information (not covered by the independent auditors’ report) should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.” Note 2 to the consolidated financial statements included in Item 8 of this report contains information on mergers and acquisitions which occurred in 2003 and 2002, as well as unaudited pro forma financial data for the years 2003 and 2002. Note 16 to the consolidated financial statements included in Item 8 contains information on operations which were discontinued in 2002.


(1)	Devon acquired another entity via a merger in 2000, which was accounted for using the pooling-of-interests method of accounting for business combinations. This accounting method required Devon to report the results of both companies as if they had always been combined. Therefore, the cash dividends per share presented through 2000 are not representative of the actual amounts paid by Devon on a historical basis. For the years 1999 and 2000, Devon’s historical cash dividends per share were $0.20 in each year.

(2)	For purposes of calculating the ratio of earnings to fixed charges and the ratio of earnings to combined fixed charges and preferred stock dividends, (i) earnings consist of earnings before income taxes, plus fixed charges; (ii) fixed charges consist of interest expense, dividends on subsidiary’s preferred stock, distributions on preferred securities of subsidiary trust, amortization of costs relating to indebtedness and the preferred securities of subsidiary trust, and one-third of rental expense estimated to be attributable to interest; and (iii) preferred stock dividends consist of the amount of pre-tax earnings required to pay dividends on the outstanding preferred stock. For the years 2002 and 1999, earnings were insufficient to cover fixed charges by $135 million and $264 million, respectively.


	For the years 2002 and 1999, earnings were insufficient to cover combined fixed charges and preferred stock dividends by $151 million and $270 million, respectively.

(3)	The preceding production, price and other data exclude the amounts related to discontinued operations for all periods presented. The preceding price data includes the effect of hedges.

(4)	Gas volumes are converted to Boe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. NGL volumes are converted to Boe on a one-to-one basis with oil. The respective prices of oil, gas and NGLs are affected by market and other factors in addition to relative energy content.

The following discussion and analysis addresses changes in Devon’s financial condition and results of operations during the three-year period of 2001 through 2003. Reference is made to “Item 6. Selected Financial Data” and “Item 8. Financial Statements and Supplementary Data.”

On April 25, 2003, Devon supplemented its property portfolio and improved its growth outlook with the Ocean merger. Former Ocean shareholders received 74 million new Devon common shares in exchange for their Ocean shares. Ocean enhances our current production profile and provides outstanding prospects for growth. We have substantially integrated the Devon and Ocean organizations and consolidated all our Houston area employees at our downtown Houston location.

2003 was a record-breaking year for Devon. We produced 228 million Boe, the highest annual production in its history. Devon’s marketing and midstream operations also contributed $286 million to operating margins. Total revenues for 2003 exceeded $7 billion, and led to record profits and operating cash flow. Devon delivered the highest net earnings, $1.7 billion, and earnings per diluted share, $8.07, in its 15 years as a public company.

Cash flow from operations was $3.8 billion for the year. This allowed Devon to fully fund our $2.6 billion of capital expenditures, retire over $500 million in long-term debt and add almost $1 billion to cash on hand. We are continuing to accumulate cash with the intent to repay debt as it matures in 2004 and subsequent years.

The significant increase in revenues and earnings resulted from both production growth and higher commodity prices. Production increased 40 million Boe, or 21%, due both to the Ocean merger and the impact of Devon’s exploration and development activities. On a pro forma basis, as if the merger had been completed on January 1, 2002, Devon increased production from retained properties year-over-year by 5.5%. Average oil, gas and NGL prices increased 18%, 61% and 33%, respectively from 2002 to 2003. Devon’s current price outlook assumes that, over the next few years, oil prices will decline toward the OPEC stated price range of $22 to $28 per barrel of oil from over $30 per barrel today and that natural gas prices will remain in a range of $3 to $5 per MMBtu for the foreseeable future. Historically, the OPEC basket price has been approximately $2 per barrel less than the NYMEX price.

In addition to dramatically increasing production and revenues, the Ocean merger increased expenses in most categories. Furthermore, higher oil, gas and NGL prices have led to upward pressure on many of Devon’s expenses such as power and fuel. Higher oil and gas prices have also led to higher demand for oilfield supplies and services, and have often caused increases in the costs of such goods and services. However, these same commodity price increases have also resulted in higher costs that are opportunity-driven. For example, with the increase in oil, gas and NGL prices, more well workovers and repairs and maintenance costs can be profitably performed to maintain or increase production volumes.

Additionally, the weakening of the U.S. dollar versus the Canadian dollar caused increases in all of our Canadian dollar expenses as expressed in U.S. dollars. This contributed approximately $88 million in aggregate, or $0.39 per Boe, of increase in 2003 production and operating costs, depreciation, depletion and

amortization expenses and general and administrative expenses. Based on Devon’s assumption that the average Canadian-to-U.S. dollar exchange rate will increase from $0.7160 in 2003 to $0.7600 in 2004, the exchange rate effect would increase these expense categories another $58 million, or $0.23 per Boe from 2003 to 2004.

Because oil, gas and NGL prices are influenced by many factors outside of its control, Devon’s management has focused its efforts on increasing oil and gas reserves and production and controlling costs. Devon’s future earnings and cash flows are dependent on its ability to continue to contain its overall cost structure at a level that will allow for profitable production.

Devon drilled almost 300 exploration wells and over 1,900 development wells during 2003. We incurred finding and development costs, including business combinations, of $7.9 billion in 2003. Including 556 million Boe of proved reserves that were acquired, Devon replaced 321% of annual production, closing 2003 with proved reserves of 2.1 billion Boe. This resulted in per-unit finding and development costs, including business combinations, which are higher than both Devon’s historical and the industry averages. Management is focused on lowering our per-unit finding and development costs in future years.

The timing differences that often occur between the years in which capital costs are incurred and the years in which related proved reserves are booked contributed significantly to the higher per-unit finding and development costs in recent years. For example, Devon had several potential discoveries in 2003 from our exploration program. We believe our deepwater Gulf of Mexico discoveries at St. Malo and Sturgis, and the 2002 Cascade and Tuk M-18 discoveries will contribute significantly to Devon’s proved reserves. However, due to the long-term nature of these projects, additional testing and approval of development plans are needed before we can record the potential reserves as proved. Therefore, we have not yet recorded any reserves related to these projects, even though the costs of drilling the wells have already been included in our finding and development costs.

Another contributor to 2003 finding and development costs related to the development of previously booked undeveloped reserves. We invested about $900 million of capital in 2003 developing reserves previously classified as proved undeveloped. Many of these reserves were associated with assets acquired in the Ocean and other recent acquisitions. This has allowed us to reduce our percentage of reserves classified as proved undeveloped from 31% following the Ocean merger to 24% at year-end.

As we begin recording proved reserves within the next 12 to 18 months from some of our recent discoveries, and as we reduce the amount of costs incurred to develop proved undeveloped reserves, we are optimistic that Devon’s per-unit finding and development costs will decline to more competitive levels.

During 2003, Devon marked its 15th anniversary as a public company. While Devon has consistently increased production over this 15-year period, volatility in oil, gas and NGL prices has resulted in considerable variability in earnings and cash flows. Prices for oil, natural gas and NGLs are determined primarily by market conditions. Market conditions for these products have been, and will continue to be, influenced by regional and worldwide economic activity, weather and other factors that are beyond Devon’s control. Devon’s future earnings and cash flows will continue to depend on market conditions.

Like all oil and gas exploration and production companies, Devon faces the challenge of natural production decline. As initial reservoir pressures are depleted, oil and gas production from a given well naturally decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or gas it produces. Historically, Devon has been able to overcome this natural decline by adding, through drilling and acquisitions, more reserves than it produces. Devon’s future growth will depend on its ability to continue to add reserves in excess of production.

In summary, as we head into 2004 and beyond, Devon is poised to continue growing organically through both our long-term investment in high-impact exploration projects and our lower-risk development of proved undeveloped reserves. In addition, we expect to continue to strengthen our balance sheet through the accumulation of cash to meet future debt maturities.

Changes in oil, gas and NGL production, prices and revenues from 2001 to 2003 are shown in the following tables. (Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2003

or

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 000-30176


Delaware		73-1567067
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

20 North Broadway, Oklahoma City, Oklahoma		73102-8260
(Address of Principal Executive Offices)		(Zip Code)


Title of each class		Name of each exchange on which registered

Common Stock, par value $.10 per share		American Stock Exchange
4.90% Convertible Debentures, due 2008		The New York Stock Exchange
4.95% Convertible Debentures, due 2008		The New York Stock Exchange


		Page

PART I
Item 1.	Business		5
Item 2.	Properties		13
Item 3.	Legal Proceedings		22
Item 4.	Submission of Matters to a Vote of Security Holders		23
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		24
Item 6.	Selected Financial Data		25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		60
Item 8.	Financial Statements and Supplementary Data		66
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		137
Item 9A.	Controls and Procedures		137
PART III
Item 10.	Directors and Executive Officers of the Registrant		138
Item 11.	Executive Compensation		138
Item 12.	Security Ownership of Certain Beneficial Owners and Management		138
Item 13.	Certain Relationships and Related Transactions		138
Item 14.	Principal Auditor Fees and Services		138
PART IV
Item 15.	Exhibits, Financial Statements and Schedules, and Reports on Form 8-K		139
SIGNATURES			147
EXHIBIT INDEX
EXHIBITS
Registrant's Restated Certificate of Incorporation
Supplemental Indenture No. 2
Statement of Computation of Ratios of Earnings
Consent of KPMG LLP
Consent of LaRoche Petroleum Consultants
Consent of Paddock Lindstrom & Associates Ltd.
Consent of Ryder Scott Company, L.P.
Consent of Gilbert Laustsen Jung Associates Ltd.
Consent of AJM Petroleum Consultants
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906



	Development Wells												Exploratory Wells


	Gross(1)						Net(2)						Gross(1)						Net(2)

	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total

1999		654		19		673		384.96		7.85		392.81		111		36		147		77.56		23.41		100.97
2000		1,095		20		1,115		600.63		10.55		611.18		166		47		213		121.02		32.69		153.71
2001		1,208		46		1,254		760.88		29.95		790.83		236		55		291		188.53		34.88		223.41
2002		1,382		27		1,409		1,035.47		19.72		1,055.19		217		59		276		148.38		41.24		189.62
2003		1,884		52		1,936		1,267.19		36.83		1,304.02		232		61		293		152.87		38.02		190.89

Total		6,223		164		6,387		4,049.13		104.90		4,154.03		962		258		1,220		688.36		170.24		858.60

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	2003						2002						2001

	Prepared			Audited			Prepared			Audited			Prepared			Audited

Domestic		33	%		37	%		12	%		61	%		67	%		9	%
Canada		28	%		—			31	%		—			43	%		—
International		98	%		—			100	%		—			100	%		—


		Total		Proved		Proved
		Proved		Developed		Undeveloped
		Reserves		Reserves		Reserves

Total Reserves
	Oil (MMBbls)		661		408		253
	Gas (Bcf)		7,316		5,980		1,336
	NGL (MMBbls)		209		179		30
	MMBoe(1)		2,089		1,584		505
	Pre-tax Future Net Revenue ($ millions)(2)		40,637		30,920		9,717
	Pre-tax 10% Present Value ($ millions)(2)		22,652		17,209		5,443
	Standardized measure of discounted future net cash flows ($ millions)(3)		15,921
U.S. Reserves
	Oil (MMBbls)		212		171		41
	Gas (Bcf)		4,884		3,935		949
	NGL (MMBbls)		161		136		25
	MMBoe(1)		1,187		964		223
	Pre-tax Future Net Revenue ($ millions)(2)		23,786		19,301		4,485
	Pre-tax 10% Present Value ($ millions)(2)		13,345		10,829		2,516
	Standardized measure of discounted future net cash flows ($ millions)(3)		9,503



	Oil Wells				Gas Wells				Total Wells

	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)

U.S.		10,466		3,591		15,247		9,738		25,713		13,329
Canada		2,686		1,763		4,117		2,410		6,803		4,173
International		507		222		4		2		511		224

Total		13,659		5,576		19,368		12,150		33,027		17,726


																	Standardized
																	Measure of
																	Discounted
													10% Present				Future Net
			Oil		Gas		NGLs				MMBoe		Value		10% Present		Cash Flows
			(MMBbls)		(Bcf)		(MMBbls)		MMBoe(1)		%(2)		(In millions)(3)		Value %(4)		(In millions)(5)

United States
	Permian Basin			92		351		17		167		8.0%	$	1,825		8.0%
	Mid-Continent			4		1,707		102		390		18.7%		3,481		15.4%
	Rocky Mountain			21		1,021		8		200		9.6%		2,128		9.4%
	Gulf Offshore			81		702		5		203		9.7%		3,405		15.0%
	Gulf Coast Onshore			14		1,103		29		227		10.9%		2,506		11.1%

Total U.S.				212		4,884		161		1,187		56.9%		13,345		58.9%	$	9,503
Canada
		Total(6)		148		2,297		48		579		27.7%		5,930		26.2%		4,123
International
		Total		301		135		—		323		15.4%		3,377		14.9%		2,295

Grand Total				661		7,316		209		2,089		100.0%	$	22,652		100.0%	$	15,921


Item 4.	*Submission of Matters to a Vote of Security Holders*


Item 5.	*Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities*



	American Stock Exchange						The Toronto Stock Exchange

	High		Low		Average Daily		High		Low		Average Daily
	(US$)		(US$)		Volume		(CN$)		(CN$)		Volume

2002:
Quarter Ended March 31, 2002		49.10		34.40		1,197,478		77.46		54.70		12,353
Quarter Ended June 30, 2002		52.28		45.05		1,005,613		79.54		71.50		2,840
Quarter Ended September 30, 2002		49.70		33.87		1,047,531		76.97		54.55		2,897
Quarter Ended December 31, 2002		53.10		42.14		1,123,356		82.50		67.25		1,222
2003:
Quarter Ended March 31, 2003		50.37		42.45		1,448,721		75.60		65.00		379
Quarter Ended June 30, 2003		56.65		45.25		1,703,900		74.74		64.96		959
Quarter Ended September 30, 2003		53.48		46.38		1,448,736		74.13		63.73		1,370
Quarter Ended December 31, 2003		58.80		45.90		1,386,548		78.20		61.00		1,534



			Year Ended December 31,

			2003		2002			2001		2000		1999


			(In millions, except per share data and ratios)
Operating Results
	Total revenues		$	7,352		4,316			2,864		2,587		1,140
	Total operating costs and expenses			4,710		3,775			2,672		1,431		1,309

	Earnings (loss) from operations			2,642		541			192		1,156		(169	)
	Net other expenses			397		675			164		118		99

	Earnings (loss) from continuing operations before income taxes and cumulative effect of change in accounting principle			2,245		(134	)		28		1,038		(268	)
	Total income tax expense (benefit)			514		(193	)		5		377		(75	)

	Earnings (loss) from continuing operations before cumulative effect of change in accounting principle			1,731		59			23		661		(193	)
	Net results of discontinued operations			—		45			31		69		39

	Earnings (loss) before cumulative effect of change in accounting principle			1,731		104			54		730		(154	)
	Cumulative effect of change in accounting principle, net of tax			16		—			49		—		—

	Net earnings (loss)		$	1,747		104			103		730		(154	)

	Net earnings (loss) applicable to common stockholders		$	1,737		94			93		720		(158	)

	Basic net earnings (loss) per share:
		Earnings (loss) from continuing operations	$	8.24		0.32			0.09		5.13		(2.13	)
		Net results of discontinued operations		—		0.29			0.25		0.53		0.45
		Cumulative effect of change in accounting principle		0.08		—			0.39		—		—

		Net earnings (loss)	$	8.32		0.61			0.73		5.66		(1.68	)

	Diluted net earnings (loss) per share:
		Earnings (loss) from continuing operations	$	8.00		0.32			0.09		4.97		(2.13	)
		Net results of discontinued operations		—		0.29			0.25		0.53		0.45
		Cumulative effect of change in accounting principle		0.07		—			0.38		—		—

		Net earnings (loss)	$	8.07		0.61			0.72		5.50		(1.68	)

	Cash dividends per common share(1)		$	0.20		0.20			0.20		0.17		0.14
	Weighted average common shares outstanding:
		Basic		209		155			128		127		94
		Diluted		217		156			130		132		99



		December 31,

		2003		2002		2001		2000		1999


		(In millions)
Balance Sheet Data
	Total assets	$	27,162		16,225		13,184		6,860		6,096
	Long-term debt	$	8,580		7,562		6,589		2,049		2,416
	Preferred stock of a subsidiary	$	55		—		—		—		—
	Stockholders’ equity	$	11,056		4,653		3,259		3,277		2,521


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*


Item 1.	*Business*



	Development Wells												Exploratory Wells


	Gross(1)						Net(2)						Gross(1)						Net(2)

	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total

1999		547		8		555		345.35		3.80		349.15		71		9		80		51.91		5.78		57.69
2000		890		13		903		512.18		6.80		518.98		95		11		106		80.09		7.41		87.50
2001		961		19		980		638.26		12.91		651.17		148		17		165		122.61		11.53		134.14
2002		933		7		940		725.79		4.67		730.46		21		18		39		19.60		12.00		31.60
2003		1,250		31		1,281		850.06		23.00		873.06		22		22		44		14.99		12.14		27.13

Total		4,581		78		4,659		3,071.64		51.18		3,122.82		357		77		434		289.20		48.86		338.06



	Development Wells												Exploratory Wells


	Gross(1)						Net(2)						Gross(1)						Net(2)

	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total

1999		65		9		74		29.61		3.45		33.06		39		23		62		25.15		16.03		41.18
2000		130		6		136		68.74		3.25		71.99		70		27		97		40.60		19.27		59.87
2001		163		26		189		100.91		16.53		117.44		82		21		103		63.96		14.05		78.01
2002		408		20		428		300.93		15.05		315.98		196		37		233		128.78		27.47		156.25
2003		586		20		606		399.48		13.33		412.81		210		34		244		137.88		23.90		161.78

Total		1,352		81		1,433		899.67		51.61		951.28		597		142		739		396.37		100.72		497.09



	Development Wells												Exploratory Wells


	Gross(1)						Net(2)						Gross(1)						Net(2)

	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total

1999		42		2		44		10.00		0.60		10.60		1		4		5		0.50		1.60		2.10
2000		75		1		76		19.71		0.50		20.21		1		9		10		0.33		6.01		6.34
2001		84		1		85		21.71		0.51		22.22		6		17		23		1.96		9.30		11.26
2002		41		—		41		8.75		—		8.75		—		4		4		—		1.77		1.77
2003		48		1		49		17.65		0.50		18.15		—		5		5		—		1.98		1.98

Total		290		5		295		77.82		2.11		79.93		8		39		47		2.79		20.66		23.45



		Total


		Year Ended December 31,

				2003 vs					2002 vs
		2003		2002(2)			2002		2001(2)			2001

Production
	Oil (MMBbls)		62		+48	%		42		+17	%		36
	Gas (Bcf)		863		+13	%		761		+56	%		489
	NGLs (MMBbls)		22		+11	%		19		+138	%		8
	Oil, gas and NGLs (MMBoe)(1)		228		+21	%		188		+50	%		126
Average Prices
	Oil (per Bbl)	$	25.63		+18	%		21.71		+1	%		21.41
	Gas (per Mcf)	$	4.51		+61	%		2.80		-27	%		3.84
	NGLs (per Bbl)	$	18.65		+33	%		14.05		-17	%		16.99
	Oil, gas and NGLs (per Boe)(1)	$	25.88		+47	%		17.61		-21	%		22.19
Revenues ($ in millions)
	Oil	$	1,588		+75	%		909		+16	%		784
	Gas	$	3,897		+83	%		2,133		+14	%		1,878
	NGLs	$	407		+48	%		275		+110	%		131

	Oil, gas and NGLs	$	5,892		+78	%		3,317		+19	%		2,793



		Domestic


		Year Ended December 31,

				2003 vs					2002 vs
		2003		2002(2)			2002		2001(2)			2001

Production
	Oil (MMBbls)		31		+31	%		24		-8	%		26
	Gas (Bcf)		589		+22	%		482		+28	%		376
	NGLs (MMBbls)		17		+16	%		14		+133	%		6
	Oil, gas and NGLs (MMBoe)(1)		146		+23	%		118		+24	%		95
Average Prices
	Oil (per Bbl)	$	27.64		+26	%		21.99		-2	%		22.36
	Gas (per Mcf)	$	4.50		+55	%		2.91		-30	%		4.17
	NGLs (per Bbl)	$	17.31		+29	%		13.37		-22	%		17.15
	Oil, gas and NGLs (per Boe)(1)	$	26.02		+46	%		17.87		-25	%		23.80
Revenues ($ in millions)
	Oil	$	861		+64	%		524		-11	%		586
	Gas	$	2,652		+89	%		1,403		-11	%		1,571
	NGLs	$	289		+51	%		192		+86	%		103

	Oil, gas and NGLs	$	3,802		+79	%		2,119		-6	%		2,260