UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(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, 2005
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-32318

Devon Energy Corporation

(Exact name of Registrant as Specified in its Charter)

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)

Registrant’s telephone number, including area code:

(405) 235-3611

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

Title of each class	Name of each exchange on which registered
Common Stock, par value $0.10 per share	The New York Stock Exchange
4.90% Exchangeable Debentures, due 2008	The New York Stock Exchange
4.95% Exchangeable Debentures, due 2008	The New York Stock Exchange

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

None

          Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act).     Yes þ     No o

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes o     No þ

          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.     Yes þ     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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ          Accelerated filer o          Non-accelerated filer o

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

          The aggregate market value of the voting stock held by non-affiliates of the registrant as of June 30, 2005, was $22,809,387,806.

          On February 28, 2006, 441,865,011 shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Proxy statement for the 2006 annual meeting of stockholders — Part III

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		5
Item 1A.	Risk Factors		13
Item 1B.	Unresolved Staff Comments		16
Item 2.	Properties		16
Item 3.	Legal Proceedings		25
Item 4.	Submission of Matters to a Vote of Security Holders		26
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		27
Item 6.	Selected Financial Data		28
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		59
Item 8.	Financial Statements and Supplementary Data		61
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		123
Item 9A.	Controls and Procedures		123
Item 9B.	Other Information		125
PART III
Item 10.	Directors and Executive Officers of the Registrant		126
Item 11.	Executive Compensation		126
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		126
Item 13.	Certain Relationships and Related Transactions		126
Item 14.	Principal Accountant Fees and Services		126
PART IV
Item 15.	Exhibits and Financial Statement Schedules		127
SIGNATURES			134
EXHIBIT INDEX
EXHIBITS
Bylaws
First Supplemental Indenture
Third Supplemental Indenture
Third Supplemental Indenture
Statement of Computations of Ratio of Earnings
Registrant's Significant Subsidiaries
Consent of KPMG LLP
Consent of LaRoche Petroleum Consultants
Consent of Ryder Scott Company, LP
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

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DEFINITIONS

      As used in this document:

      “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.

      “FPSO” means floating, production, storage and offloading facilities.

      “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.

      “SEC” means United States Securities and Exchange Commission.

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

      “United States Onshore” means the properties of Devon in the continental United States.

      “United States Offshore” means the properties of Devon in the 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.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

      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 our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information which was used to prepare the December 31, 2005 reserve reports and other data in our possession or available from third parties. In addition, forward-looking

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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 we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

•  energy markets;

•  production levels, including Canadian production subject to government royalties which fluctuate with prices and international production governed by payout agreements which affect reported production;

•  reserve levels;

•  operating results;

•  competitive conditions;

•  technology;

•  the availability of capital resources;

•  capital expenditure and other contractual 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 we or our subsidiaries conduct business;

•  legislative or regulatory changes, including changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations;

•  terrorism;

•  occurrence of property acquisitions or divestitures;

•  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. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

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PART I

Item 1. Business

General

      Devon Energy Corporation, including its subsidiaries, (“Devon”) is an independent energy company engaged primarily in oil and gas exploration, development and production, the transportation of oil, gas, and NGLs and the processing of natural gas. We own oil and gas properties principally in the United States and Canada and, to a lesser degree, various regions located outside North America, including Azerbaijan, Brazil, China, Egypt, Russia and West Africa. In addition to our oil and gas operations, we have marketing and midstream operations. These include the marketing of 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 our significant properties and associated 2005 developments can be found under “Item 2. Properties”.

      Through our predecessors, we began operations in 1971 as a privately held company. In 1988, our common stock began trading publicly on the American Stock Exchange under the symbol “DVN”. In October 2004, we transferred our common stock listing to the New York Stock Exchange. Our principal and administrative offices are located at 20 North Broadway, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).

Availability of Reports

      We make available free of charge on our internet website, www.devonenergy.com, our 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 we electronically file or furnish them to the SEC.

Strategy

      We have a two-pronged operating strategy. First, we invest the vast majority of our capital budget in low-risk exploitation and development projects on our extensive North American property base which provides reliable and repeatable production and reserves additions. To supplement that strategy, we annually invest a measured amount of capital in high-impact, long-cycle time projects to replenish our development inventory for the future. The philosophy that underlies the execution of this strategy is to strive to increase value on a per share basis by:

•  building oil and gas reserves and production;

•  exercising capital discipline;

•  preserving financial flexibility;

•  maintaining a low unit-cost structure; and

•  improving performance through our marketing and midstream operations.

Financial Information about Segments and Geographical Areas

      Notes 14 and 15 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain information on our segments and geographical areas.

Development of Business

      During 1988, we expanded our capital base with our first issuance of common stock to the public. This transaction began a substantial expansion program that has continued through the subsequent years. This expansion is attributable to both a focused mergers and acquisitions program spanning a number of years and an active ongoing exploration and development drilling program. Total proved reserves increased

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from 8 MMBoe at year-end 1987 (without giving effect to the 1998 and 2000 mergers accounted for as poolings of interests) to 2,112 MMBoe at year-end 2005.

      During the same time period, we have grown proved reserves from 0.66 Boe per diluted share at year-end 1987 (without giving effect to the 1998 and 2000 poolings) to 4.49 Boe per diluted share at year-end 2005. This represents a compound annual growth rate of 12%. We also increased production from 0.09 Boe per diluted share in 1987 (without giving effect to the 1998 and 2000 poolings) to 0.48 Boe per diluted share in 2005, a compound annual growth rate of 10%. This per share growth is a direct result of successful execution of our strategic plan and other key transactions and events. A number of these recent key transactions and events, as well as a summary of our recent drilling activities are presented below and in the next section of this report entitled “Drilling Activities”:

•  Ocean Energy, Inc. (“Ocean”)—On April 25, 2003, we acquired Ocean for a total purchase price of $3.8 billion and added 554 million Boe to our proved reserves.

•  Mitchell Energy & Development Corp. (“Mitchell”)—On January 24, 2002, we acquired Mitchell for a total purchase price of $3.2 billion and added 404 million Boe to our proved reserves.

•  Anderson Exploration Ltd. (“Anderson”)—On October 15, 2001, we acquired Anderson for a total purchase price of $3.5 billion and added 534 million Boe to our proved reserves.

•  Property Divestitures—During the first half of 2005, we sold non-core oil and gas properties in the offshore Gulf of Mexico and onshore in the United States and Canada. The asset sales generated $1.8 billion of proceeds, net of tax, for the 176 million Boe of proved reserves that were sold. By divesting these properties, we lengthened our overall reserve life and lowered our overall cost structure and improved operating efficiency of our retained properties. In 2002, we also sold non-core oil and gas properties, representing 199 million Boe of proved reserves, for $1.4 billion of proceeds.

•  Share Repurchases—In August 2005, we completed a share repurchase program that began in October 2004. Under this program, we repurchased 49.6 million shares of our common stock at a total cost of $2.3 billion, or $46.69 per share. On August 3, 2005, we announced another program to repurchase up to an additional 50 million shares of our common stock. As of February 28, 2006, we had repurchased 4.4 million shares for $267 million, or $60.40 per share, under this program. This program can be discontinued at any time.

Drilling Activities

      The following tables set forth the results of our drilling activity for the past five years.

Total Properties

	Development Wells												Exploratory Wells
	Gross(1)						Net(2)						Gross(1)						Net(2)
	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total
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
2004		1,864		40		1,904		1,155.87		29.38		1,185.25		231		43		274		158.43		20.99		179.42
2005		2,060		19		2,079		1,341.80		13.40		1,355.20		254		42		296		164.30		23.20		187.50
Total		8,398		184		8,582		5,561.21		129.28		5,690.49		1,170		260		1,430		812.51		158.33		970.84

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United States Properties

	Development Wells												Exploratory Wells
	Gross(1)						Net(2)						Gross(1)						Net(2)
	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total
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
2004		1,200		17		1,217		719.43		11.67		731.10		23		17		40		11.24		6.81		18.05
2005		1,236		13		1,249		782.30		8.20		790.50		34		15		49		18.60		6.50		25.10
Total		5,580		87		5,667		3,715.84		60.45		3,776.29		248		89		337		187.04		48.98		236.02

Canadian Properties

	Development Wells												Exploratory Wells
	Gross(1)						Net(2)						Gross(1)						Net(2)
	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total
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
2004		598		23		621		413.14		17.71		430.85		206		22		228		145.69		12.08		157.77
2005		780		6		786		546.80		5.20		552.00		217		17		234		144.20		12.40		156.60
Total		2,535		95		2,630		1,761.26		67.82		1,829.08		911		131		1,042		620.51		89.90		710.41

International Properties

	Development Wells												Exploratory Wells
	Gross(1)						Net(2)						Gross(1)						Net(2)
	Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total		Productive		Dry		Total
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
2004		66		—		66		23.30		—		23.30		2		4		6		1.50		2.10		3.60
2005		44		—		44		12.70		—		12.70		3		10		13		1.50		4.30		5.80
Total		283		2		285		84.11		1.01		85.12		11		40		51		4.96		19.45		24.41

(1)	Gross wells are the sum of all wells in which we own an interest.
(2)	Net wells are gross wells multiplied by our fractional working interests therein.

      As of December 31, 2005, we were participating in the drilling of 149 gross (99.37 net) wells in the U.S., 33 gross (16.55 net) wells in Canada and 35 gross (8.58 net) wells internationally. Of these wells, through February 1, 2006, 57 gross (34.13 net) wells in the U.S., 11 gross (8.90 net) wells in Canada, and 2 gross (0.30 net) wells internationally had been completed as productive. An additional 1 gross (0.06 net) well in the U.S was a dry hole. The remaining wells were still in progress.

Customers

      We sell our 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.

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      The principal customers for our 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 trucked or shipped to storage, refining or pipeline facilities.

      No purchaser accounted for over 10% of our revenues in 2005.

Oil and Natural Gas Marketing

      The spot market for oil and gas is subject to volatility as supply and demand factors fluctuate. We may periodically enter into financial hedging arrangements, fixed-price contracts or firm delivery commitments with a portion of our oil and gas production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Oil Marketing

      Our 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

      Our 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 2006, approximately 79% of our 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 which dedicate the natural gas to a purchaser for an extended period of time, but still at market sensitive prices. Our remaining gas production was sold under long-term fixed price contracts.

Marketing and Midstream Activities

      The primary objective of our marketing and midstream group is to add value to us and other producers to whom we provide such services by gathering, processing and marketing oil and gas production in a timely and efficient manner. Our most significant marketing and midstream asset is the Bridgeport processing plant and gathering system located in North Texas. These facilities serve not only our gas production from the Barnett Shale but also gas production of other producers in the area.

      Our marketing and midstream revenue sources are primarily generated by:

•  selling NGLs that are either extracted from the gas streams processed by our plants or purchased from third parties for marketing, and

•  selling or gathering gas that moves through our transport pipelines and unrelated third party pipelines.

      Our marketing and midstream costs and expenses are primarily incurred from:

•  purchasing the gas streams entering our transport pipelines and plants;

•  purchasing fuel needed to operate our plants, compressors and related pipeline facilities;

•  purchasing third-party NGLs;

•  operating our plants, gathering systems and related facilities; and

•  transporting products on unrelated third party pipelines.

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Competition

      See “Item 1A. Risk Factors”.

Seasonal Nature of Business

      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.

Government Regulation

      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, numerous government agencies have issued extensive laws 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, production and marketing and midstream activities. These laws and regulations 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, we are unable to predict the future cost or impact of complying with such laws and regulations. However, we do not expect that any of these laws and regulations will affect our operations in a manner materially different than they would affect other oil and gas companies of similar size.

      The following are significant areas of government control and regulation in the United States, Canada and international locations in which we operate.

United States Regulation

      Exploration and Production. Our 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 transportation of production. Our operations are also subject to various conservation regulations, 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 we can produce from our wells and to limit the number of wells or the locations at which we can drill.

      Certain oil and gas leases, including our offshore Gulf of Mexico leases, most of our leases in the San Juan Basin and many of our 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

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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 our exploration, development, processing, and production operations and related costs. We are also subject to laws and regulations concerning occupational safety and health. We consider the costs of environmental protection and safety and health compliance necessary and manageable parts of our business. We maintain our 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 our compliance procedures. We have been able to plan for and comply with new environmental and safety and health initiatives without materially altering our operating strategies.

      We maintain levels of insurance customary in the industry to limit our 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 because of violation of any federal, state or local law. We are committed to meeting our responsibilities to protect the environment wherever we operate and anticipate 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. Our unreimbursed expenditures in 2005 concerning such matters were immaterial, but we cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

      We are 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 claims associated with these activities, we recognize liabilities when reasonable estimates are possible. Such liabilities are primarily for estimated costs associated with remediation. We have not used discounting in determining our 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 our consolidated financial statements. We adjust the liabilities 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 our 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, 2005, our consolidated balance sheet included $4 million of non-current accrued liabilities, reflected in “Other liabilities,” related to these and other environmental remediation liabilities. We do not currently believe there is a reasonable possibility of incurring additional material costs in excess of the existing liabilities recognized for such environmental remediation activities. With respect to the sites in which our subsidiaries are PRPs, our conclusion is based in large part on our (i) 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, our monetary exposure is not expected to be material.

     Canadian Regulations

      Exploration and Production. Our Canadian operations are subject to federal and provincial governmental regulations. Such regulations 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

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upon which wells have been drilled, the plugging and abandoning of wells and the transportation of production from wells. Our 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 we can produce from our wells and to limit the number of wells or the locations at which we 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 our cash flow.

      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, 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. Natural gas exports for a term of less than two years, or for a term of two to twenty years in quantities of not more than 20,000 Mcf per day, must be made pursuant to an NEB order. Any natural gas exports to be made pursuant to a contract of larger duration (to a maximum of 25 years) or in larger quantities require an exporter to obtain a license from the NEB, which requires the approval of the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts meet certain criteria prescribed by the NEB. The governments of Alberta, British Columbia and Saskatchewan 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 monitored, abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties. We are committed to meeting our responsibilities to protect the environment wherever we operate and anticipate 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. Our unreimbursed expenditures in 2005 concerning such matters were immaterial, but we cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

      The North American Free Trade Agreement. The North American Free Trade Agreement (“NAFTA”) grants Canada the freedom to determine whether exports to the United States or Mexico will be allowed. In making this determination, Canada must ensure 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.

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      Kyoto Protocol. The Kyoto 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 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 legislation related to this protocol have yet to be finalized, the effect on our operations 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.

International Regulations

      Exploration and Production. Our 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.

      Regulations include 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. Our operations are also subject to regulations which may limit the number of wells or the locations at which we can drill.

      Production Sharing Contracts. Many of our international licenses are governed by Production Sharing Contracts (“PSCs”) 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 our exploration, development, processing and production operations and related costs. 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. Additionally, the Kyoto Protocol will have requirements similar to those for Canada for the oil and gas industry in Azerbaijan, Brazil, China, Egypt, Equatorial Guinea, Nigeria and Russia. As details of the implementation of emissions reduction initiatives related to this protocol have yet to be announced, the effect on our international operations, if any, cannot be determined at this time.

Employees

      As of December 31, 2005, our staff consisted of 4,075 full-time employees. We believe we have good labor relations with our employees.

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Item 1A.     Risk Factors

      Our business activities, and the oil and gas industry in general, are subject to a variety of risks. Although we have a diversified asset base, a strong balance sheet and a history of generating sufficient cash to fund capital expenditure and investment programs and to pay dividends, if any of the following risk factors should occur, our profitability, financial condition and/or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.

Oil, Natural Gas and NGL Prices are Volatile

      Our financial results are highly dependent on the prices of and demand for oil, natural gas and NGLs. A significant downward movement of the prices for these commodities could have a material adverse effect on our estimated proved reserves, revenues and operating cash flows. Such a downward price movement could also have a material adverse effect on our profitability, the carrying value of our oil and gas properties and future growth. Historically, prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include, but are not limited to:

•  consumer demand for oil, natural gas and NGLs;

•  conservation efforts;

•  OPEC production restraints;

•  weather;

•  regional market pricing differences;

•  differing quality of oil produced (i.e., sweet crude versus heavy or sour crude) and Btu content of gas produced;

•  the level of imports and exports of oil, natural gas and NGLs;

•  the price and availability of alternative fuels;

•  the overall economic environment; and

•  governmental regulations and taxes.

Estimates of Oil, Natural Gas and NGL Reserves are Uncertain

      The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our estimates of future net revenue, as well as our financial condition and profitability. Additional discussion of our policies regarding estimating and recording reserves is described in “Item 2. Properties — Proved Reserves and Estimated Future Net Revenue”.

Discoveries or Acquisitions of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production

      The production rate from oil and gas properties generally declines as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies, identify additional producing zones in existing wells, secondary recovery reserves or

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tertiary recovery reserves, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.

Future Exploration and Drilling Results are Uncertain and Involve Substantial Costs

      Substantial costs are often required to locate and acquire properties and drill exploratory wells. Such activities are subject to numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling and completing wells are often uncertain. In addition, oil and gas properties can become damaged or drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:

•  unexpected drilling conditions;

•  pressure or irregularities in reservoir formations;

•  equipment failures or accidents;

•  fires, explosions, blow-outs and surface cratering;

•  marine risks such as capsizing, collisions and hurricanes;

•  other adverse weather conditions;

•  lack of access to pipelines or other methods of transportation;

•  environmental hazards or liabilities; and

•  shortages or delays in the delivery of equipment.

      A significant occurrence of one of these factors could result in a partial or total loss of our investment in a particular property. In addition, drilling activities may not be successful in establishing proved reserves. Such a failure could have an adverse effect on our future results of operations and financial condition. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. We are currently performing exploratory drilling activities in certain international countries. We have been granted drilling concessions in these countries that require commitments on our behalf to incur significant capital expenditures. Even if future drilling activities are unsuccessful in establishing proved reserves, we will likely be required to fulfill our commitments to make such capital expenditures.

Industry Competition For Leases, Materials, People and Capital Can Be Significant

      Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and other independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Higher recent commodity prices have increased the costs of properties available for acquisition, and there are a greater number of companies with the financial resources to pursue acquisition opportunities. Certain of our competitors have financial and other resources substantially larger than ours, and they have also established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as changing worldwide prices and levels of production, the cost and availability of alternative fuels and the application of government regulations.

International Operations Have Uncertain Political, Economic and Other Risks

      We have international operations in Angola, Azerbaijan, Brazil, China, Cote d’Ivoire, Egypt, Equatorial Guinea, Gabon, Ghana, Indonesia, Nigeria and the Russian Republic of Tatarstan. As a result,

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we face political and economic risks and other uncertainties that are less prevalent for our operations in North America. Such factors include, but are not limited to:

•  general strikes and civil unrest;

•  the risk of war, acts of terrorism, expropriation, forced renegotiation or modification of existing contracts;

•  import and export regulations;

•  taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;

•  transportation regulations and tariffs;

•  exchange controls, currency fluctuations, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds;

•  laws and policies of the United States affecting foreign trade, including trade sanctions;

•  the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate;

•  the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and

•  difficulties in enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.

      Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Various regions of the world have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. This could adversely affect our interests and our future profitability.

      The impact that future terrorist attacks or regional hostilities may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.

Government Laws and Regulations Can Change

      Our operations are subject to federal laws and regulations in the United States, Canada and the other international countries in which we operate. In addition, we are also subject to the laws and regulations of various states, provinces and local governments. Pursuant to such legislation, numerous government 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. Changes in such legislation have affected, and at times in the future could affect, our future operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Although we are unable to predict changes to existing laws and regulations, such changes could

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significantly impact our profitability. While such legislation can change at any time in the future, those laws and regulations outside North America to which we are subject generally include greater risk of unforeseen change.

Environmental Matters and Costs Can Be Significant

      As an owner or lessee and operator of oil and gas properties, we are subject to various federal, provincial, state, local and international laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from our operations in affected areas.

Insurance Does Not Cover All Risks

      Exploration, development, production and processing of oil, natural gas and NGLs can be hazardous and involve unforeseen occurrences such as hurricanes, blowouts, cratering, fires and loss of well control. These occurrences can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. We maintain insurance against certain losses or liabilities in accordance with customary industry practices and in amounts that management believes to be prudent. However, insurance against all operational risks is not available to us.

Item 1B.     Unresolved Staff Comments

      Not applicable.

Item 2. Properties

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

      We also have certain midstream assets, including natural gas and NGL processing plants and pipeline systems. Our most significant midstream assets are our assets serving the Barnett Shale development in North Texas. These assets include approximately 2,600 miles of pipeline, a 650 MMcf per day gas processing plant, and a 15,000 Bbls per day NGL fractionator.

Proved Reserves and Estimated Future Net Revenue

      The process of estimating oil, gas and NGL reserves is complex and requires significant judgment as discussed in “Item 1A. Risk Factors”. As a result, we have developed internal policies for estimating and recording reserves. Our policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance, and assign responsibilities for reserves bookings to our Reserve Evaluation Group (the “Group”). The policies also require that reserve estimates be made by qualified reserves estimators (“QREs”), as defined by the Society of Petroleum Engineers’ standards. A list of QREs is kept by the Senior Advisor — Corporate Reserves. All QREs are required to receive education covering the fundamentals of SEC proved reserves assignments.

      The Group is responsible for internal reserves evaluation and certification and includes the Manager — E&P Budgets and Reserves and the Senior Advisor — Corporate Reserves. The Group reports independently of any of our operating divisions. The Vice President — Planning and Evaluation is directly responsible for overseeing the Group and reports to the President of Devon. No portion of the Group’s compensation is dependent on the quantity of reserves booked.

      Throughout the year, the Group performs internal audits of each operating division’s reserves. Selection criteria of reserves that are audited include major fields and major changes (additions and

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revisions) to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants as discussed below.

      In addition to internal audits, we engage three independent petroleum consulting firms to perform both external reserves preparation and audits. Ryder Scott Company, L.P. prepared the reserves estimates for all offshore Gulf of Mexico properties and for 98% of the international proved reserves. LaRoche Petroleum Consultants, Ltd. audited the reserves estimates for 87% of the domestic onshore properties. AJM Petroleum Consultants prepared estimates covering 46% of our Canadian reserves and audited an additional 26% of our Canadian reserves.

      Set forth below is a summary of the reserves which were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2005, 2004 and 2003.

	2005						2004						2003
	Prepared			Audited			Prepared			Audited			Prepared			Audited
Domestic		9	%		79	%		16	%		61	%		33	%		37	%
Canada		46	%		26	%		22	%		—			28	%		—
International		98	%		—			98	%		—			98	%		—
Total		31	%		54	%		28	%		35	%		42	%		21	%

      “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 our employees and audited by an independent petroleum consultant. An audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.

      We follow what we believe to be a rational approach not only to recording oil and gas reserves, but also to subjecting these reserves to reviews by independent petroleum consultants. In 2004 and 2003, 63% of our company-wide reserves were prepared or audited by an independent petroleum consulting firm. In 2005, 85% of our company-wide reserves were prepared or audited by an independent petroleum consulting firm. We expect the 2005 percent to be indicative of the coverage provided by independent reviews in 2006. 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 five years, our annual performance related revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 1% of the previous year’s estimate.

      In addition to internal and external reviews, three independent members of our Board of Directors have been assigned to a Reserves Committee. The Reserves Committee meets at lease twice a year to discuss reserves issues and policies and periodically meets separately with our senior reserves engineering personnel and our independent petroleum consultants. The Reserves Committee assists the Board of Directors with the oversight of the following:

•  the annual review and evaluation of our consolidated oil, gas and NGL reserves;

•  the integrity of our reserves evaluation and reporting system;

•  our compliance with legal and regulatory requirements related to reserves evaluation, preparation, and disclosure;

•  the qualifications and independence of our independent engineering consultants; and

•  our business practices and ethical standards in relation to the preparation and disclosure of reserves.

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      The following table sets forth our estimated proved reserves and the related estimated pre-tax future net revenues, pre-tax 10% present value and after-tax standardized measure of discounted future net cash flows as of December 31, 2005. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 15 to our Consolidated Financial Statements included herein.

		Total		Proved		Proved
		Proved		Developed		Undeveloped
		Reserves		Reserves		Reserves
Total Reserves
	Oil (MMBbls)		649		363		286
	Gas (Bcf)		7,296		6,111		1,185
	NGLs (MMBbls)		246		216		30
	MMBoe(1)		2,112		1,599		513
	Pre-tax future net revenue (in millions)(2)	$	64,956		51,671		13,285
	Pre-tax 10% present value (in millions)(2)	$	35,610		29,135		6,475
	Standardized measure of discounted future net cash flows (in millions)(3)	$	23,574
U.S. Reserves
	Oil (MMBbls)		173		149		24
	Gas (Bcf)		5,164		4,343		821
	NGLs (MMBbls)		197		175		22
	MMBoe(1)		1,232		1,049		183
	Pre-tax future net revenue (in millions)(2)	$	38,118		32,389		5,729
	Pre-tax 10% present value (in millions)(2)	$	20,173		17,233		2,940
	Standardized measure of discounted future net cash flows (in millions)(3)	$	13,276
Canadian Reserves
	Oil (MMBbls)		253		103		150
	Gas (Bcf)		2,006		1,708		298
	NGLs (MMBbls)		49		41		8
	MMBoe(1)		636		429		207
	Pre-tax future net revenue (in millions)(2)	$	17,949		15,116		2,833
	Pre-tax 10% present value (in millions)(2)	$	9,912		8,786		1,126
	Standardized measure of discounted future net cash flows (in millions)(3)	$	6,631
International Reserves
	Oil (MMBbls)		223		111		112
	Gas (Bcf)		126		60		66
	NGLs (MMBbls)		—		—		—
	MMBoe(1)		244		121		123
	Pre-tax future net revenue (in millions)(2)	$	8,889		4,166		4,723
	Pre-tax 10% present value (in millions)(2)	$	5,525		3,116		2,409
	Standardized measure of discounted future net cash flows (in millions)(3)	$	3,667

(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.

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(2)  Estimated future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. 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 for each individual property as of December 31, 2005. 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 our properties of $45.50 per Bbl of oil, $7.84 per Mcf of natural gas and $32.46 per Bbl of NGLs. These prices compare to the December 31, 2005, NYMEX price of $61.04 per Bbl for crude oil and the Henry Hub spot price of $10.08 per MMBtu for natural gas.

We believe the pre-tax 10% present value is a useful measure in addition to standardized measure as it assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors which are consistent from company to company. We also understand that securities analysts use this measure in similar ways.

(3)  See Note 15 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data”.

      As presented in the previous table, we had 1,599 MMBoe of proved developed reserves at December 31, 2005. Proved developed reserves consist of proved developed producing reserves and proved developed non-producing reserves. The following table provides additional information regarding our proved developed reserves at December 31, 2005.

		Total		Proved		Proved
		Proved		Developed		Developed
		Developed		Producing		Non-Producing
		Reserves		Reserves		Reserves
Total Reserves
	Oil (MMBbls)		363		305		58
	Gas (Bcf)		6,111		5,449		662
	NGLs (MMBbls)		216		199		17
	MMBoe		1,599		1,412		187
U.S. Reserves
	Oil (MMBbls)		149		125		24
	Gas (Bcf)		4,343		3,913		430
	NGLs (MMBbls)		175		164		11
	MMBoe		1,049		942		107
Canadian Reserves
	Oil (MMBbls)		103		87		16
	Gas (Bcf)		1,708		1,481		227
	NGLs (MMBbls)		41		35		6
	MMBoe		429		369		60
International Reserves
	Oil (MMBbls)		111		93		18
	Gas (Bcf)		60		55		5
	NGLs (MMBbls)		—		—		—
	MMBoe		121		101		20

      No estimates of our 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

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with the SEC and (ii) in filings with the Department of Energy (“DOE”). Reserve estimates filed with the SEC correspond with the estimates of our reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that we operate and to exclude all interests in wells that we do 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, 2005. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.

Production, Revenue and Price History

      Certain information concerning oil, natural gas and NGL production, prices, revenues (net of all royalties, overriding royalties and other third party interests) and operating expenses for the three years ended December 31, 2005, is set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Well Statistics

      The following table sets forth our producing wells as of December 31, 2005:

	Oil Wells				Gas Wells				Total Wells
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
U.S.		9,039		3,134		15,459		10,656		24,498		13,790
Canada		2,840		1,985		4,004		2,292		6,844		4,277
International		589		249		4		2		593		251
Total		12,468		5,368		19,467		12,950		31,935		18,318

(1)	Gross wells are the total number of wells in which we own a working interest.
(2)	Net wells are gross wells multiplied by our fractional working interests therein.

Developed and Undeveloped Acreage

      The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2005.

		Developed				Undeveloped
		Gross(1)		Net(2)		Gross(1)		Net(2)
		(In thousands)
United States
	Permian Basin		588		309		1,138		494
	Mid-Continent		993		678		964		455
	Rocky Mountains		789		538		2,178		1,148
	Gulf Coast Onshore		860		524		812		471
	Gulf Offshore		609		384		3,272		1,635
Total U.S.			3,839		2,433		8,364		4,203
Canada			3,284		2,066		10,319		6,681
International			624		341		19,889		10,947
Grand Total			7,747		4,840		38,572		21,831

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(1)	Gross acres are the total number of acres in which we own a working interest.
(2)	Net acres are gross acres multiplied by our fractional working interests therein.

Operation of Properties

      The day-to-day operations 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.

      We are the operator of 18,784 of our wells. As operator, we receive reimbursement for direct expenses incurred in the performance of our duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.

Organization Structure

      Our 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 properties are focused in the Western Canadian Sedimentary Basin in Alberta and British Columbia. Properties outside North America are located primarily in Azerbaijan, China, Egypt and areas in West Africa, including Equatorial Guinea, Gabon, and Cote d’Ivoire. Additionally, we have exploratory interests, but no current producing assets, in other international countries including Angola, Brazil, Ghana and Nigeria. Maintaining a tight geographic focus in selected core areas has allowed us to improve operating and capital efficiency.

      The following table sets forth proved reserve information on the most significant geographic areas in which our properties are located as of December 31, 2005.

																		Standardized
																		Measure of
																		Discounted
													Pre-Tax 10%		Pre-Tax			Future Net
		Oil		Gas		NGLs				MMBoe			Present Value		10% Present			Cash Flows
		(MMBbls)		(Bcf)		(MMBbls)		MMBoe(1)		%(2)			(In millions)(3)		Value %(4)			(In millions)(5)
United States
	Permian Basin		91		285		23		161		7.6	%	$	2,832		8.0	%
	Mid-Continent		5		2,282		124		509		24.1	%		6,292		17.7	%
	Rocky Mountain		22		1,074		8		209		9.9	%		3,336		9.4	%
	Gulf Coast Onshore		11		1,120		38		237		11.2	%		3,817		10.7	%
	Gulf Offshore		44		403		4		116		5.5	%		3,896		10.9	%
Total U.S			173		5,164		197		1,232		58.3	%		20,173		56.7	%	$	13,276
Canada(6)			253		2,006		49		636		30.1	%		9,912		27.8	%		6,631
International			223		126		—		244		11.6	%		5,525		15.5	%		3,667
Grand Total			649		7,296		246		2,112		100.0	%	$	35,610		100.0	%	$	23,574

(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.
(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. See a discussion of the difference between the pre-tax 10% present value and

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	standardized measure in footnote 2 of “Item 2. Properties — Proved Reserves and Estimated Future Net Revenues.”
(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 $1.00 Canadian: $0.8577 U.S.

United States

Permian Basin

      Our Permian Basin assets are located in portions of Southeast New Mexico and West Texas. These assets include conventional oil and gas properties producing from a wide variety of geologic formations and depths. Our leasehold position in Southeast New Mexico encompasses 108,000 net acres of developed lands and 221,000 net acres of undeveloped land and minerals. Historically, we have 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 portion of the Permian Basin, we maintain 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. We also own a significant acreage position in West Texas with more than 200,000 net acres of developed lands and more than 273,000 net acres of undeveloped land and minerals at December 31, 2005.

Mid-Continent

      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. Our Mid-Continent production has historically come from conventional oil and gas properties. However, the Barnett Shale in North Texas, acquired in 2002, is a non-conventional gas resource. The Mid-Continent region represented 24% of our proved reserves at December 31, 2005. Approximately 80% of our proved reserves in the Mid-Continent area are in the Barnett Shale.

      The Barnett Shale, our 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. However, the application of available technology has made the Barnett Shale a low-risk and highly profitable natural gas operation. Cumulative natural gas production from our wells in the Barnett Shale surpassed one trillion cubic feet during 2005. We hold 552,000 net acres and over 2,100 producing wells in the Barnett Shale. Our average working interest is more than 80%.

      We have been successful in 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 to increase production rates. We are also applying horizontal drilling, closer well spacing and reservoir optimization techniques to further enhance the value of the Barnett Shale.

      Our marketing and midstream operations gather and process our Barnett Shale production along with Barnett Shale production from unrelated third parties. The Barnett Shale gathering system consists of approximately 2,600 miles of pipeline, a 650 MMcf per day gas processing plant, and a 15,000 Bbls per day NGL fractionator.

      In 2006, we plan to drill a total of 325 new Barnett Shale wells including 266 horizontal and 59 vertical wells. We began an infill drilling program on our core area acreage in 2005 and plan to drill 50 to 60 horizontal infill wells in 2006. Current net production from the Barnett Shale is approximately 95 MBoe per day.

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Rocky Mountain

      Our 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 natural gas projects. Approximately 17% of our proved reserves in the Rocky Mountains are from coalbed natural gas. We began producing coalbed natural gas in the San Juan Basin of New Mexico in the mid-1980s and began drilling coalbed natural gas wells in the Powder River Basin of Wyoming in 1998. As of December 31, 2005, we had approximately 1,360 producing coalbed natural gas wells in the Powder River Basin. Net coalbed natural gas production from the basin was approximately 11 MBoe per day as of December 31, 2005. We plan to drill about 250 new wells in the Powder River Basin in 2006.

      The Washakie field in Wyoming is another significant natural gas producing area in our Rocky Mountain region. In 2005, we drilled 88 wells in the Washakie field, including 53 wells we operate. In 2006, we plan to drill up to 70 wells and participate in another 35 outside-operated wells. We have interests in over 200,000 gross acres and an inventory of more than 300 drilling locations. Our current net production from Washakie is approximately 16 MBoe per day.

Gulf Coast Onshore

      Our Gulf Coast onshore properties are located in South and East Texas, Louisiana and Mississippi. Most of the wells in the region are completed in conventional sandstone formations.

      Our operations in South Texas have focused on exploration in the Edwards, Wilcox and Frio-Vicksburg formations. We drilled three exploratory discoveries on our Gulf Coast acreage in 2005. Drilling plans in 2006 include 34 new wells and 64 recompletions.

      East Texas is an important conventional gas producing region, and Carthage and Groesbeck are two of the primary producing areas of this region. Wells produce from the Cotton Valley sands, the Travis Peak sands and from shallower sands and carbonates. We have interests in over 2,300 producing wells in East Texas and plans to drill 139 wells in Carthage and over 30 wells in Groesbeck in 2006.

      We have an active exploration program under way in the Bossier Trend in North Louisiana. We hold about 200,000 net acres in seven Bossier prospect areas. We drilled exploratory test wells on the Vixen and North Vixen prospects in 2005. Plans for 2006 include test wells on three additional Bossier prospects.

Gulf Offshore

      The offshore Gulf of Mexico accounted for 13% of our 2005 production. We operate over 300 platforms and caissons in the Gulf of Mexico. Gulf of Mexico operations are typically differentiated by water depth. The shallow water shelf is defined by water depths of 600 feet or less. We operate in both the shelf and deepwater areas.

      In 2005, we continued development of the deepwater Magnolia field (Garden Banks 783). At December 31, 2005, six Magnolia wells were producing approximately 10 MBoe per day to our interest. The final two Magnolia producing wells will be completed in 2006. Also in 2006, we will complete two producing gas wells in the deepwater Merganser field (Atwater Valley 37). Merganser will produce into the Independence Hub, which is expected to be completed in early 2007. We expect our net share of production from Merganser to be approximately eight MBoe per day.

      In addition to our producing properties, we have a significant inventory of exploration prospects in the Gulf of Mexico. The current prospect inventory includes 15 shelf prospects, 18 deepwater prospects in the lower Tertiary trend and 17 deepwater Miocene prospects.

      On the shallow-water shelf, the industry is exploring for oil and gas reserves at depths in excess of 15,000 feet. We drilled a “deep shelf” discovery well on the Big Bend prospect (Mustang Island A-110) in 2005. We are the operator of Big Bend with a 50% working interest.

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      In the deepwater Gulf of Mexico, almost all historical production of oil and gas has been from Miocene aged reservoirs. We currently produce approximately 50 MBoe per day from the deepwater Gulf. During 2006, we expect to drill exploratory wells on three Miocene prospects.

      In recent years, the industry has begun to explore for oil below the Miocene in older formations that are collectively referred to as the lower Tertiary. To date, we have participated in three lower Tertiary discoveries.

      Cascade (Walker Ridge 206) was our first discovery in the lower Tertiary trend. We drilled successful appraisal wells on the prospect in 2005. Also in 2005, we drilled a successful appraisal of the Jack lower Tertiary discovery (Walker Ridge 759). An extended production test of the Jack appraisal well is planned for 2006. Using information obtained from a successful production test, we and our partners will be able to determine a development plan for the Jack discovery. We hold 25% working interests in Jack and Cascade. Our third lower Tertiary discovery is St. Malo (Walker Ridge 678). Additional appraisal drilling on St. Malo is pending partner approval and rig availability. We have a 22.5% working interest in the St. Malo discovery.

Canada

      We are among the largest independent oil and gas producers in Canada and operate in most of the producing basins in Western Canada. As of December 31, 2005, 30% of our proved reserves were in Canada.

      Many of the Canadian basins where we operate 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. We expect to drill about 380 wells in the 2005-2006 winter program in Canada.

      We hold approximately 410,000 net undeveloped acres in the Deep Basin in West-Central Alberta, where we drilled 179 wells in 2005 and have another active drilling program planned for 2006. The profitability of our operations in the Deep Basin is enhanced by our ownership in nine gas processing plants in the area. Deep Basin reservoirs tend to be rich in liquids, producing up to 50 barrels of NGLs with each MMcf of gas.

      Other important oil and gas exploration and development areas in Canada include the Peace River Arch, Northeast British Columbia, Central Alberta and the Lloydminster region of Alberta and Saskatchewan. At Lloydminster, cold flow heavy oil is found in multiple horizons generally at depths of 1,000 to 2,000 feet. In 2005, we acquired 165,000 net acres in the Iron River area within the greater Lloydminster region. We expect to drill 800 wells at Iron River over the next four years.

      The oil sands of Eastern Alberta are a vast North American hydrocarbon resource. We hold over 75,000 net acres of oil sands leases in Alberta. In 2004, we received final regulatory approval to proceed with development of our Jackfish thermal oil sands project, in which we have a 100% working interest. The project is expected to produce 35 MBbls per day of heavy oil when fully operational in 2008. We expect to drill 34 horizontal wells at Jackfish in 2006 along with the construction of the Access dual pipeline. Access will transport diluent and blended crude oil between Jackfish and Edmonton.

International

      Beyond our core properties in the United States and Canada, we also look outside North America for longer-term reserve and production growth. At December 31, 2005, these international areas accounted for 12% of our worldwide proved reserves.

      The most significant international producing property is the ExxonMobil-operated Zafiro oil field on Block B, offshore Equatorial Guinea in West Africa. During 2005, our share of production from Zafiro averaged 37 MBbls per day. We expect to drill nine development wells on Block B in 2006. We drilled a discovery on the Esmeralda prospect on Block B in 2005. We have also identified exploratory prospects on

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Block B and on three additional blocks in Equatorial Guinea. Three exploratory wells are planned on Block P in 2006. We drilled a discovery well on the Venus prospect on Block P in 2005.

      Our second most significant international producing asset is our Panyu project offshore China. Panyu, in the Pearl River Mouth of the South China Sea, was discovered in 1998. Panyu production began late in 2003. We drilled and completed five successful development wells and tested two exploratory prospects during 2005. During 2005, our share of production from China was 15 MBbls per day.

      We also have an active offshore exploration program in Brazil. We made a discovery in 2004 offshore Brazil on Block BM-C-8. Development of the Polvo discovery commenced in 2005 and first production is expected in 2007. We, in partnership with Petrobras on three blocks, were the successful bidder on three offshore blocks in Brazil’s bid round seven in 2005. We expect to drill five exploration wells in Brazil in 2006.

      In Azerbaijan, we have a 5.6% carried working interest in the Azeri-Chirag-Gunashli, or ACG, oil development project in the Caspian Sea. We estimate that the ACG field contains over five billion barrels of gross proved oil reserves. Oil production from the ACG field began ramping up in 2005 after the Central Azeri platform came on-line.. Based on economic factors existing at December 31, 2005, our net share of ACG production is expected to increase to between 30 to 35 MBbls per day in early 2007 when payout is reached.

      We also hold interests in Angola, Cote d’Ivoire, Egypt, Gabon, Ghana, Indonesia, Nigeria, and Russia. Exploratory wells in Egypt and Nigeria are planned for 2006.

Title to Properties

      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. We believe 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, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations, generally including a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.

Item 3. Legal Proceedings

Royalty Matters

      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 we are 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. Trial is set for February 2007 if the suit continues to advance. We believe that we have acted reasonably, have legitimate and strong defenses to all allegations in the suit, and have paid royalties in good faith. We do not currently believe that we are subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.

      We have been a defendant in certain private royalty owner litigation filed in Wyoming regarding deductibility of certain post production costs from royalties we pay. A significant portion of such

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production is, or will be, transported through facilities owned by Thunder Creek Gas Services, L.L.C., of which we own a 75% interest. During 2005, all of the litigation was resolved for immaterial amounts.

Equatorial Guinea Investigation

      The SEC has been conducting an inquiry into payments made to the government of Equatorial Guinea, and to officials and persons affiliated with officials of the government of Equatorial Guinea. On August 9, 2005, we received a subpoena issued by the SEC pursuant to a formal order of investigation. We have cooperated fully with the SEC’s previous requests for information in this inquiry and plan to continue to work with the SEC in connection with its formal investigation.

Other Matters

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

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

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

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PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

Market Price

      Our common stock has been traded on the New York Stock Exchange (the “NYSE”) since October 12, 2004. Prior to October 12, 2004, our common stock was traded on the American Stock Exchange (the “AMEX”).

      The following table sets forth the high and low sales prices for our common stock as reported by the NYSE and AMEX for the periods indicated.

	New York Stock
	Exchange/American
	Stock Exchange
	High		Low
2004:
Quarter Ended March 31, 2004	$	30.56		25.88
Quarter Ended June 30, 2004	$	33.75		28.68
Quarter Ended September 30, 2004	$	37.90		31.61
Quarter Ended December 31, 2004	$	41.64		34.55
2005:
Quarter Ended March 31, 2005	$	49.42		36.48
Quarter Ended June 30, 2005	$	52.31		40.60
Quarter Ended September 30, 2005	$	70.35		50.75
Quarter Ended December 31, 2005	$	69.79		54.01

      On February 28, 2006, there were 16,576 holders of record of our common stock.

Dividends

      We commenced the payment of regular quarterly cash dividends on our common stock on June 30, 1993, in the amount of $0.015 per share. Effective December 31, 1996, we increased our quarterly dividend payment to $0.025 per share. Effective March 31, 2004, we increased our quarterly dividend payment to $0.05 per share. Effective March 31, 2005, we increased the quarterly dividend payment to $0.075 per share. Effective March 31, 2006, we will increase the quarterly dividend payment to $0.1125 per share. We anticipate continuing to pay regular quarterly dividends in the foreseeable future.

Issuer Purchases of Equity Securities

      The following table presents the fourth quarter of 2005 activity with respect to our stock repurchase program announced August 3, 2005.

					Total Number of Shares		Maximum Number of
	Total Number				Purchased as Part of		Shares that May Yet Be
	of Shares		Average Price		Publicly Announced		Purchased Under the
Period	Purchased		Paid per Share		Plans or Programs(1)		Plans or Programs
October		2,189,500	$	60.26		2,189,500		47,810,500
November		36,100	$	54.61		36,100		47,774,400
December		—		—		—		47,774,400
Total		2,225,600	$	60.16		2,225,600

(1)  On August 3, 2005, we announced our plan to repurchase up to 50 million shares of our common shares. The repurchase program is planned to extend through 2007. Under this program, we are not obligated to acquire any specific number of shares and may discontinue the program at any time.

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Item 6. Selected Financial Data

      The following selected financial information (not covered by the report of independent registered accounting firm) should be read in conjunction with “Item 1. Business — Development of Business,” “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 the merger which occurred in 2003, as well as unaudited pro forma financial data for 2003.

			Year Ended December 31,
			2005		2004		2003		2002			2001
			(In millions, except prices and per Boe amounts)
Operating Results
	Total revenues		$	10,741		9,189		7,352		4,316			2,864
	Total expenses and other income, net			6,189		5,896		5,107		4,450			2,836
	Earnings (loss) from continuing operations before income tax expense and cumulative effect of change in accounting principle			4,552		3,293		2,245		(134	)		28
	Total income tax expense (benefit)			1,622		1,107		514		(193	)		5
	Earnings from continuing operations before cumulative effect of change in accounting principle			2,930		2,186		1,731		59			23
	Net results of discontinued operations			—		—		—		45			31
	Earnings before cumulative effect of change in accounting principle			2,930		2,186		1,731		104			54
	Cumulative effect of change in accounting principle, net of tax			—		—		16		—			49
	Net earnings		$	2,930		2,186		1,747		104			103
	Net earnings applicable to common stockholders		$	2,920		2,176		1,737		94			93
	Basic net earnings per share:
		Earnings from continuing operations	$	6.38		4.51		4.12		0.16			0.05
		Net results of discontinued operations		—		—		—		0.15			0.12
		Cumulative effect of change in accounting principle		—		—		0.04		—			0.20
		Net earnings	$	6.38		4.51		4.16		0.31			0.37
	Diluted net earnings per share:
		Earnings from continuing operations	$	6.26		4.38		4.00		0.16			0.05
		Net results of discontinued operations		—		—		—		0.14			0.12
		Cumulative effect of change in accounting principle		—		—		0.04		—			0.19
		Net earnings	$	6.26		4.38		4.04		0.30			0.36
	Cash dividends per common share		$	0.30		0.20		0.10		0.10			0.10
	Weighted average common shares outstanding:
		Basic		458		482		417		309			255
		Diluted		470		499		433		313			259
	Ratio of earnings to fixed charges(1)			8.32		6.73		4.87		N/A			1.12
	Ratio of earnings to combined fixed charges and preferred stock dividends(1)			8.12		6.56		4.74		N/A			1.05

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			Year Ended December 31,
			2005			2004			2003			2002			2001
			(In millions, except prices and per Boe amounts)
Cash Flow Data
	Net cash provided by operating activities		$	5,612			4,816			3,768			1,754			1,910
	Net cash used in investing activities		$	(1,652	)		(3,634	)		(2,773	)		(2,046	)		(5,285	)
	Net cash (used in) provided by financing activities		$	(3,543	)		(1,001	)		(414	)		401			3,370
Production, Price and Other Data(2)
	Production:
		Oil (MMBbls)		64			78			62			42			36
		Gas (Bcf)		827			891			863			761			489
		NGLs (MMBbls)		24			24			22			19			8
		MMBoe(3)		226			251			228			188			126
	Average prices:
		Oil (Per Bbl)	$	38.44			28.18			25.63			21.71			21.41
		Gas (Per Mcf)	$	6.99			5.32			4.51			2.80			3.84
		NGLs (Per Bbl)	$	28.96			23.04			18.65			14.05			16.99
		Per Boe(3)	$	39.59			29.88			25.88			17.61			22.19
	Costs per Boe:(3)
		Production and operating expenses	$	7.43			6.13			5.63			4.71			5.29
		Depreciation, depletion and amortization of oil and gas properties	$	8.99			8.54			7.33			5.88			6.30

		December 31,
		2005		2004		2003		2002		2001
		(In millions)
Balance Sheet Data
	Total assets	$	30,273		30,025		27,162		16,225		13,184
	Long-term debt	$	5,957		7,031		8,580		7,562		6,589
	Stockholders’ equity	$	14,862		13,674		11,056		4,653		3,259

(1)	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 year 2002, earnings were insufficient to cover fixed charges by $135 million. For the year 2002, earnings were insufficient to cover combined fixed charges and preferred stock dividends by $151 million.
(2)	The preceding production, price and other data for 2002 and 2001 excludes the amounts related to discontinued operations. The preceding price data includes the effect of derivative financial instruments and fixed-price physical delivery contracts.
(3)	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.

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

Introduction

      The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Reference is made to “Item 6. Selected Financial Data” and “Item 8. Financial Statements and Supplementary Data.” The following is discussed and analyzed:

•  Overview of Business

•  Overview of 2005 Results and Outlook

•  Results of Operations

•  Capital Resources, Uses and Liquidity

•  Contingencies and Legal Matters

•  Critical Accounting Policies and Estimates

•  Recently Issued Accounting Standards Not Yet Adopted

•  2006 Estimates

Overview of Business

      Devon is the largest U.S.-based independent oil and gas producer and one of the largest independent processors of natural gas and natural gas liquids in North America. Our portfolio of oil and gas properties provides stable production and a platform for future growth. About 88 percent of our production is from North America. We also operate in selected international areas, including Azerbaijan, Brazil, China, Egypt, Russia and West Africa. Our production mix is about 61 percent natural gas and 39 percent oil and natural gas liquids such as propane, butane and ethane. We produce 2.3 billion cubic feet of natural gas each day, about 3 percent of all the gas consumed in North America.

      In managing our global operations, we have an operating strategy that is focused on creating and increasing value per share. Key elements of this strategy are replacing oil and gas reserves, growing production and exercising capital discipline. We must also control operating costs and manage commodity pricing risks to achieve long-term success. The discussion and analysis of our results of operations and other related information will refer to these factors.

•  Oil and gas reserve replacement — Our financial condition and profitability are significantly affected by the amount of proved reserves we have. Oil and gas properties are our most significant asset, and the reserves that relate to such properties are key to our future success. As we produce these reserves, our estimated proved reserves decline materially. Therefore, we must conduct successful exploration and development activities or acquire additional properties containing proved reserves to replace reserves that have been produced.

•  Production growth — Our profitability and operating cash flows are largely dependent on the amount of oil, gas and NGLs we produce. Furthermore, growing production from existing properties is difficult because the rate of production from oil and gas properties generally declines as reserves are depleted. As a result, we constantly drill for new proved reserves and develop proved undeveloped reserves on properties that provide a balance of near-term and long-term production. In addition, we may acquire properties with proved reserves that we can develop to help us meet our production goals.

•  Capital investment discipline — Effectively deploying our resources into capital projects is key to helping us maintain and grow future production and oil and gas reserves. Therefore, maintaining a disciplined approach to investing in capital projects is important to our profitability and financial

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	condition. Also, our ability to control capital expenditures can be affected by changes in commodity prices. During times of high commodity prices, drilling and related costs often escalate due to the effects of supply versus demand economics. Approximately 85% of our investment in capital projects is dedicated to a foundation of low-risk projects primarily in North America. The remainder of our capital is invested in high-impact projects primarily in the Gulf of Mexico, Brazil and West Africa. By deploying our capital in this manner, we are able to consistently deliver cost-efficient drill-bit growth and provide a strong source of cash flow while balancing short-term and long-term growth targets.
•	Operating cost controls — To maintain our competitive position, we must control our lease operating costs and other production costs. As reservoirs are depleted and production rates decline, per unit production costs will generally increase and affect our profitability and operating cash flows. Similar to capital expenditures, our ability to control operating costs can be affected when commodity prices rise significantly. Our base North American production is focused in core areas of our operations where we can achieve economies of scale to assist in our management of operating costs.
•	Commodity pricing risks — Our profitability is highly dependent on the prices of oil, natural gas and NGLs. Prices for oil, 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 our control. To manage this volatility in the past, we have utilized financial hedging arrangements and fixed-price contracts on a portion of our production and may use such instruments in the future.

Overview of 2005 Results and Outlook

      2005 was the best year in our history. We continued to execute our strategy to increase value per share. As a result, we delivered record amounts for certain key measures of our financial and operating performance in 2005:

•  Net earnings for the year climbed 34% to $2.9 billion

•  Earnings per share climbed more than 40% to $6.26 per diluted share

•  Net cash provided by operating activities reached $5.6 billion

•  Estimated proved reserves at December 31, 2005 were 2.1 billion Boe

•  Estimated proved reserves increased 439 million Boe through drilling, extensions and performance revisions

•  Capital expenditures for oil and gas exploration and development activities were $3.9 billion

•  Combined realized price for oil, gas and NGLs increased 32% to $39.59

•  Marketing and midstream margin rose 25% to $450 million

      We produced 226 million Boe in 2005, representing a 10% decrease compared to 2004. Excluding the effects of production lost due to the sale of non-core properties in the first half of 2005 and production suspended due to hurricanes in the last half of 2005, our year-over-year production increased 1%. In addition, with the significant increase in commodity prices and the weakened U.S. dollar compared to the Canadian dollar, operating costs also increased. Per unit lease operating expenses increased 17% to $5.95 per Boe.

      In 2005, we utilized cash flow from operations and the proceeds from the sale of non-core properties to fund our $4.1 billion in capital expenditures, repay $1.3 billion in debt and repurchase $2.3 billion of our common stock. In August 2005, we announced a plan to repurchase up to 50 million additional shares of our common stock by the end of 2007. As of February 28, 2006, we had repurchased 4.4 million shares under this program.

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      We have laid the foundation for continued growth in future years, at competitive unit-costs, that we expect will create additional value for our investors. In 2006, we expect to deliver reserve additions of 410 to 440 million Boe with related capital in the range of $4.6 to $4.8 billion. We expect production to remain relatively flat from 2005 to 2006 for our retained properties. However, we expect an 8% increase in 2007 production over 2006, reflecting the significant reserve additions in 2004 and 2005, and those expected in 2006.

Results of Operations

Revenues

      Changes in oil, gas and NGL production, prices and revenues from 2003 to 2005 are shown in the following tables. (Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)

		Total
		Year Ended December 31,
				2005 vs					2004 vs
		2005		2004(2)			2004		2003(2)			2003
Production
	Oil (MMBbls)		64		-18	%		78		+26	%		62
	Gas (Bcf)		827		-7	%		891		+3	%		863
	NGLs (MMBbls)		24		-1	%		24		+10	%		22
	Oil, gas and NGLs (MMBoe)(1)		226		-10	%		251		+10	%		228
Average Prices
	Oil (per Bbl)	$	38.44		+36	%		28.18		+10	%		25.63
	Gas (per Mcf)	$	6.99		+32	%		5.32		+18	%		4.51
	NGLs (per Bbl)	$	28.96		+26	%		23.04		+24	%		18.65
	Oil, gas and NGLs (per Boe)(1)	$	39.59		+32	%		29.88		+15	%		25.88
Revenues ($ in millions)
	Oil	$	2,478		+13	%		2,202		+39	%		1,588
	Gas		5,784		+22	%		4,732		+21	%		3,897
	NGLs		687		+24	%		554		+36	%		407
	Oil, gas and NGLs	$	8,949		+20	%		7,488		+27	%		5,892

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		Domestic
		Year Ended December 31,
				2005 vs					2004 vs
		2005		2004(2)			2004		2003(2)			2003
Production
	Oil (MMBbls)		25		-19	%		31		+2	%		31
	Gas (Bcf)		555		-8	%		602		+2	%		589
	NGLs (MMBbls)		18		-4	%		19		+13	%		17
	Oil, gas and NGLs (MMBoe)(1)		136		-10	%		151		+3	%		146
Average Prices
	Oil (per Bbl)	$	41.64		+35	%		30.84		+12	%		27.64
	Gas (per Mcf)	$	7.08		+30	%		5.43		+21	%		4.50
	NGLs (per Bbl)	$	26.68		+24	%		21.47		+24	%		17.31
	Oil, gas and NGLs (per Boe)(1)	$	40.21		+31	%		30.80		+18	%		26.02
Revenues ($ in millions)
	Oil	$	1,062		+9	%		976		+13	%		861
	Gas		3,929		+20	%		3,261		+23	%		2,652
	NGLs		484		+19	%		405		+40	%		289
	Oil, gas and NGLs	$	5,475		+18	%		4,642		+22	%		3,802

		Canada
		Year Ended December 31,
				2005 vs					2004 vs
		2005		2004(2)			2004		2003(2)			2003
Production
	Oil (MMBbls)		13		-5	%		14		+3	%		14
	Gas (Bcf)		261		-6	%		279		+4	%		267
	NGLs (MMBbls)		6		+8	%		5		-1	%		5
	Oil, gas and NGLs (MMBoe)(1)		62		-5	%		65		+4	%		63
Average Prices
	Oil (per Bbl)	$	26.88		+24	%		21.60		-8	%		23.54
	Gas (per Mcf)	$	6.95		+35	%		5.15		+13	%		4.57
	NGLs (per Bbl)	$	37.19		+27	%		29.23		+27	%		23.08
	Oil, gas and NGLs (per Boe)(1)	$	38.17		+33	%		28.80		+10	%		26.25
Revenues ($ in millions)
	Oil	$	353		+18	%		299		-6	%		318
	Gas		1,814		+26	%		1,437		+18	%		1,222
	NGLs		196		+38	%		143		+25	%		114
	Oil, gas and NGLs	$	2,363		+26	%		1,879		+14	%		1,654

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		International
		Year Ended December 31,
				2005 vs					2004 vs
		2005		2004(2)			2004		2003(2)		2003
Production
	Oil (MMBbls)		26		-21	%		33		+88%		17
	Gas (Bcf)		11		+6	%		10		+52%		7
	NGLs (MMBbls)		—		N/M			—		N/M		—
	Oil, gas and NGLs (MMBoe)(1)		28		-19	%		35		+86%		19
Average Prices
	Oil (per Bbl)	$	41.16		+45	%		28.40		+20%		23.64
	Gas (per Mcf)	$	3.76		+13	%		3.33		-4%		3.47
	NGLs (per Bbl)	$	22.81		+8	%		21.12		-2%		21.45
	Oil, gas and NGLs (per Boe)(1)	$	39.76		+42	%		27.92		+19%		23.45
Revenues ($ in millions)
	Oil	$	1,063		+15	%		927		+126%		409
	Gas		41		+20	%		34		+46%		23
	NGLs		7		+12	%		6		+68%		4
	Oil, gas and NGLs	$	1,111		+15	%		967		+122%		436

(1)	Gas volumes are converted to Boe or MMBoe 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.
(2)	All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.

N/ M Not meaningful.

      The average prices shown in the preceding tables include the effect of our oil and gas price hedging activities. Following is a comparison of our average prices with and without the effect of hedges for each of the last three years.

	With Hedges						Without Hedges
	2005		2004		2003		2005		2004		2003
Oil (per Bbl)	$	38.44		28.18		25.63		48.49		35.99		27.67
Gas (per Mcf)	$	6.99		5.32		4.51		7.14		5.39		4.79
NGLs (per Bbl)	$	28.96		23.04		18.65		28.96		23.04		18.65
Oil, gas and NGLs (per Boe)	$	39.59		29.88		25.88		42.98		32.60		27.48

Oil Revenues

      2005 vs. 2004 Oil revenues increased $276 million in 2005. Oil revenues increased $661 million due to a $10.26 increase in the average realized price of oil. A decrease in 2005 production of 14 million barrels caused oil revenues to decrease by $385 million. Production lost from the 2005 property divestitures accounted for seven million barrels of the decrease. We also suspended certain domestic oil production in 2005 and 2004 due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan. The year over year impact accounted for an additional one million barrels of suspended production in 2005 than in 2004. The remainder of the decrease is due to certain international properties in which our ownership interest decreased after we recovered our costs under the applicable production sharing contracts.

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      2004 vs. 2003 Oil revenues increased $614 million in 2004. An increase in 2004 production of 16 million barrels caused oil revenues to increase by $415 million. The April 2003 Ocean merger accounted for 14 million barrels of increased production. The remaining increase is primarily related to new production from China partially offset by natural production declines and the effects of Hurricane Ivan on domestic properties in 2004. Oil revenues increased $199 million due to a $2.55 increase in the average realized price of oil.

Gas Revenues

      2005 vs. 2004 Gas revenues increased $1.1 billion in 2005. A $1.67 per Mcf increase in the average realized gas price caused revenues to increase by $1.4 billion. A decrease in 2005 production of 64 Bcf caused gas revenues to decrease by $337 million. Production associated with the 2005 property divestitures caused a decrease of 89 Bcf. We also suspended certain domestic gas production in 2005 and 2004 due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan. The year over year impact accounted for an additional 12 Bcf of suspended production in 2005 than in 2004. These decreases were more than offset by new drilling and development and increased performance in U.S. offshore and onshore properties.

      2004 vs. 2003 Gas revenues increased $835 million in 2004. An $0.81 per Mcf increase in the average realized gas price caused revenues to increase by $714 million. An increase in 2004 production of 28 Bcf caused gas revenues to increase by $121 million. The April 2003 Ocean merger accounted for 43 Bcf of increased production. This was offset by a production decrease in domestic properties as a result of natural declines and the effects of Hurricane Ivan in 2004.

NGL Revenues

      2005 vs. 2004 NGL revenues increased $133 million in 2005. A $5.92 per barrel increase in average NGL prices caused revenues to increase by $141 million. A slight decrease in 2005 production due to 2005 property divestitures and suspended production in 2005 due to Hurricanes Katrina, Rita and Dennis caused revenues to decrease by $8 million.

      2004 vs. 2003 NGL revenues increased $147 million in 2004. A $4.39 per barrel increase in average NGL prices caused revenues to increase by $106 million. An increase in 2004 production of 2 million barrels caused revenues to increase $41 million. The April 2003 Ocean merger accounted for 0.6 million barrels of increased production. The remaining production increase was primarily related to new drilling and development in the Barnett Shale properties.

Marketing and Midstream Revenues

      2005 vs. 2004 Marketing and midstream revenues increased $91 million in 2005. Of this increase, approximately $442 million was the result of higher overall market prices for natural gas and NGLs. This was partially offset by $338 million in lower revenues resulting primarily from the sale of certain assets in 2004 and 2005. Additionally, revenues decreased $13 million primarily due to lower third-party natural gas and NGL throughput volumes.

      2004 vs. 2003 Marketing and midstream revenues increased $241 million in 2004. Of this increase, approximately $218 million was the result of higher overall market prices for natural gas and NGLs. Additionally, revenues increased $103 million due to higher third-party natural gas and NGL throughput volumes. This was partially offset by $80 million in lower revenues resulting primarily from the sale of certain assets in 2004.

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Oil, Gas and NGL Production and Operating Expenses

      The details of the changes in oil, gas and NGL production and operating expenses between 2003 and 2005 are shown in the table below.

				Year Ended December 31,
						2005 vs					2004 vs
				2005		2004(1)			2004		2003(1)			2003
Expenses ($ in millions):
	Production and operating expenses:
		Lease operating expenses		$	1,345		+5	%		1,280		+19	%		1,078
		Production taxes			335		+31	%		255		+25	%		204
			Total production and operating expenses	$	1,680		+9	%		1,535		+19	%		1,282
Expenses per Boe:
	Production and operating expenses:
		Lease operating expenses		$	5.95		+17	%		5.11		+8	%		4.73
		Production taxes			1.48		+45	%		1.02		+13	%		0.90
			Total production and operating expenses	$	7.43		+21	%		6.13		+9	%		5.63

(1)  All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.

      2005 vs. 2004 Lease operating expenses increased $65 million in 2005. The increase in lease operating expense was largely caused by higher commodity prices. With the increase in oil, gas and NGL prices, more well workovers and repairs and maintenance costs were performed to either maintain or improve production volumes. Other costs, including ad valorem taxes, power and fuel costs increased primarily as a result of higher commodity prices. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $30 million increase in costs. Partially offsetting these increases was a decrease of $144 million in lease operating expenses related to properties that were sold in 2005.

      The increases described above were also the primary factors causing lease operating expenses per Boe to increase. Although we divested properties that had higher per-unit operating costs, the cost escalation largely related to higher commodity prices and the weaker U.S. dollar compared to the Canadian dollar had a greater effect on our per unit costs than the property divestitures.

      Production taxes increased $80 million in 2005. The majority of our production taxes are assessed on our onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the 18% increase in domestic oil, gas and NGL revenues was the primary cause of the production tax increase. In addition, production taxes related to our international production increased $26 million due to higher export tax rates in Russia as well as higher oil revenues in China and Russia.

      2004 vs. 2003 Lease operating expenses increased $202 million in 2004. The April 2003 Ocean merger accounted for $84 million of the increase. Lease operating expenses on our historical properties increased $88 million, due to an increase in well workover expenses, ad valorem taxes and power, fuel, casualty insurance and repairs and maintenance costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $30 million increase in costs.

      The increase in lease operating expenses per Boe is primarily related to increased well workover expenses, ad valorem taxes and power, fuel and repairs and maintenance costs, as well as the changes in the Canadian-to-U.S. dollar exchange rate.

      Production taxes increased $51 million in 2004. The 22% increase in domestic oil, gas and NGL revenues was the primary cause of the production tax increase.

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Depreciation, Depletion and Amortization of Oil and Gas Properties (“DD&A”)

      DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced during the year, by the “depletable base”. The depletable base represents the net capitalized investment plus future development costs in those reserves. Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.

      2005 vs. 2004 Oil and gas property related DD&A decreased $110 million in 2005. DD&A decreased $210 million due to a 10% decrease in the combined oil, gas and NGL production in 2005. This decrease was partially offset by an increase in the consolidated DD&A rate from $8.54 per BOE in 2004 to $8.99 per BOE in 2005 which caused oil and gas property related DD&A to increase by $100 million. In 2005, finding and development costs for reserve discoveries and extensions were lower than previous years but were higher than the 2004 DD&A rate of $8.54 which caused the 2005 rate to increase $0.49. With the higher commodity prices, current development costs and estimates of future development costs increased in 2005 compared to 2004. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused the rate to increase $0.17. These increases were partially offset by a $0.21 decrease in the rate as a result of our 2005 property divestitures.

      2004 vs. 2003 Oil and gas property related DD&A increased $473 million in 2004. An increase in the consolidated DD&A rate from $7.33 per BOE in 2003 to $8.54 per BOE in 2004 caused oil and gas property related DD&A to increase by $305 million. The increase in the DD&A rate is primarily related to the April 2003 Ocean merger, negative reserve revisions in Canada and certain international countries subject to production sharing contracts and changes in the Canadian-to-U.S. dollar exchange rate. A 10% increase in 2004 oil, gas and NGL production caused DD&A to increase $168 million.

Marketing and Midstream Operating Costs and Expenses

      2005 vs. 2004 Marketing and midstream operating costs and expenses increased $3 million in 2005. Of this increase, approximately $306 million was the result of an increase in prices paid for natural gas and NGLs. This was partially offset by $297 million in lower costs and expenses resulting primarily from the sale of certain assets in 2004 and 2005. Additionally, operating costs and expenses decreased $6 million primarily due to lower third-party natural gas and NGL throughput volumes.

      2004 vs. 2003 Marketing and midstream operating costs and expenses increased $165 million in 2004. Of this increase, approximately $133 million was the result of an increase in prices paid for natural gas and NGLs. Additionally, operating costs and expenses increased $106 million due to higher third-party natural gas and NGL throughput volumes. This was partially offset by $74 million in lower costs and expenses resulting primarily from the sale of certain assets in 2004.

General and Administrative Expenses (“G&A”)

      Our net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A capitalized pursuant to the full cost method of accounting related to exploration and development activities. The other is the amount of G&A reimbursed by working interest owners of properties for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. Net G&A includes

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expenses related to oil, gas and NGL exploration and production activities, as well as marketing and midstream activities. See the following table for a summary of G&A expenses by component.

		Year Ended December 31,
					2005 vs						2004 vs
		2005			2004			2004			2003			2003
		($ in millions)
Gross G&A		$	584			+6	%		549			+5	%		524
Capitalized G&A			(189	)		+10	%		(172	)		+22	%		(140	)
Reimbursed G&A			(104	)		+4	%		(100	)		+29	%		(77	)
	Net G&A	$	291			+5	%		277			-10	%		307

      2005 vs. 2004 Gross G&A increased $35 million. Higher employee compensation and benefits costs caused gross G&A to increase $38 million. Of this increase, $17 million related to higher restricted stock compensation primarily due to our December 2005 and 2004 grants. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $9 million increase in costs. These increases were offset by an $8 million decrease in rent expense resulting primarily from the abandonment of certain Canadian office space in 2004.

      The $17 million increase in capitalized G&A resulted primarily from the higher salaries and benefits related to oil and gas exploration and development capital projects. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused capitalized G&A to increase $3 million.

      2004 vs. 2003 Gross G&A increased $25 million. The April 2003 Ocean merger increased gross expenses $27 million primarily due to the inclusion of an additional four months of Ocean activities in 2004 compared to 2003. Also, higher compensation and benefit costs, increased charitable contributions and the abandonment of certain Canadian office space increased gross G&A $26 million, $12 million and $5 million, respectively. During 2004, we also incurred $6 million of incremental professional fees related to additional activities performed to comply with the requirements of Section 404 of The Sarbanes-Oxley Act of 2002. Finally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $8 million increase in costs. These increases were partially offset by the synergies obtained from the Ocean merger.

      The increase in both capitalized G&A of $32 million and reimbursed G&A of $23 million was primarily related to the increased activity subsequent to the April 2003 Ocean merger.

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Reduction of Carrying Value of Oil and Gas Properties

      During 2005 and 2003, we reduced the carrying value of our oil and gas properties due to full cost ceiling limitations and unsuccessful exploratory activities. A detailed description of how full cost ceiling limitations are determined is included in the Critical Accounting Policies and Estimates section of this report. A summary of these reductions and additional discussion is provided below.

			Year Ended December 31,
			2005				2003
					Net of				Net of
			Gross		Taxes		Gross		Taxes
			(In millions)
Ceiling test reductions:
	Egypt		$	—		—		45		26
	Indonesia			—		—		4		1
	Russia			—		—		19		9
Unsuccessful exploratory reductions:
	Angola			170		119		—		—
	Brazil			42		42		11		7
	Ghana			—		—		26		26
	Other			—		—		6		5
		Total	$	212		161		111		74

2005 Reductions

      Our interests in Angola were acquired through the Ocean Energy acquisition. Our drilling program has been unsuccessful in Angola, resulting in no proven reserves for the country. After drilling three unsuccessful wells in the fourth quarter of 2005, we determined that all of the Angolan capitalized costs should be impaired. Devon has a commitment to drill one additional well in Angola by the end of August 2006.

      Prior to the fourth quarter of 2005, we were capitalizing the costs of previous unsuccessful efforts in Brazil pending the determination of whether proved reserves would be recorded in Brazil. We have been successful in our drilling efforts on block BM-C-8 in Brazil, and are currently developing our Polvo project on this block. The ultimate value of the Polvo project is expected to be in excess of the sum of its related costs, plus the costs of the previous unrelated unsuccessful efforts in Brazil which were capitalized. However, the Polvo proved reserves will be recorded over a period of time. It is expected that a small initial portion of the proved reserves ultimately expected at Polvo will be recorded in 2006. Based on preliminary estimates developed in the fourth quarter of 2005, the value of this initial partial booking of proved reserves will not be sufficient to offset the sum of the related proportionate Polvo costs plus the costs of the previous unrelated unsuccessful efforts. Therefore, we determined that the prior unsuccessful costs unrelated to the Polvo project should be impaired. These costs totaled approximately $42 million. There is no tax benefit related to the Brazilian impairment.

2003 Reductions

      The Egyptian reduction was primarily due to poor results of a development well that was unsuccessful in the primary objective. Partially as a result of this well, we revised Egyptian proved reserves downward. The Russian reduction was primarily the result of additional capital costs incurred as well as an increase in operating costs. The Indonesian reduction was primarily related to an increase in operating costs and a reduction in proved reserves.

      Additionally, during 2003, we elected to discontinue certain exploratory activities in Ghana, certain properties in Brazil and other smaller concessions. After meeting the drilling and capital commitments on

39

these properties, we determined that these properties did not meet our internal criteria to justify further investment. Accordingly, we recorded a charge associated with the impairment of these properties.

Interest Expense

      The following schedule includes the components of interest expense between 2003 and 2005.

		2005			2004			2003
		(In millions)
Interest based on debt outstanding		$	507			513			531
Accretion of debt discount, net			4			2			3
Facility and agency fees			2			2			1
Amortization of capitalized loan costs			7			22			12
Capitalized interest			(70	)		(70	)		(50	)
Early retirement premiums			76			—			—
Other			7			6			5
	Total interest expense	$	533			475			502

      2005 vs. 2004 The average debt balance decreased from $8.2 billion in 2004 to $7.4 billion in 2005 due to debt repayments during 2004 and 2005. This decrease in debt outstanding caused interest expense to decrease $53 million. This decrease in interest expense was partially offset by a $47 million increase due to higher floating rates in 2005. The average interest rate on outstanding debt increased from 6.3% in 2004 to 6.8% in 2005.

      Other items included in interest expense that are not related to the debt balance outstanding were $64 million higher in 2005. Of this increase, $51 million related to the early retirement premium for the redemption of the $400 million 6.75% notes and $25 million related to the loss on the early redemption of the zero coupon convertible senior debentures. In conjunction with the early redemption of the senior debentures, we also expensed $5 million in remaining unamortized issuance costs. This was partially offset by $16 million of unamortized debt issuance costs that were expensed in the second quarter of 2004 upon the early repayment of the outstanding balance under our $3 billion term loan credit facility.

      2004 vs. 2003 The average debt balance outstanding decreased from $8.6 billion in 2003 to $8.2 billion in 2004 causing interest expense to decrease $22 million. The decrease in average debt outstanding was due to debt repayments during 2004. The average interest rate on outstanding debt increased from 6.2% in 2003 to 6.3% in 2004. The higher rate in 2004 caused interest expense to increase $4 million.

      Other items included in interest expense that are not related to the debt balance outstanding were $9 million lower in 2004. Of this decrease, $20 million related to the capitalization of interest. The increase in interest capitalized was primarily related to additional unproved properties acquired from the April 2003 Ocean Energy merger and the nature of the properties acquired. The Ocean properties included significant deepwater Gulf and international exploratory properties and major development projects. The effect of the $20 million increase in capitalized interest was partially offset by the $16 million of debt issuance costs that were expensed in 2004 as a result of the early repayment of the outstanding balance under our $3 billion term loan credit facility.

Effects of Changes in Foreign Currency Exchange Rates

      Our Canadian subsidiary, which has designated the Canadian dollar as its functional currency, had $400 million 6.75% senior notes outstanding which were denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar while the notes were outstanding increased or decreased the expected amount of Canadian dollars eventually required to repay the notes. In addition, our Canadian subsidiary has cash and other working capital amounts denominated in U.S. dollars which

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also fluctuate in value with changes in the exchange rate. Such changes in the Canadian dollar equivalent balance of the debt and working capital balances are required to be included in determining net earnings for the period in which the exchange rate changes.

      The changes in the Canadian-to-U.S. dollar exchange rate from $0.8308 at December 31, 2004 to $0.8503 at the redemption date of the Canadian senior notes resulted in a gain of $9 million in 2005. Also in 2005, our Canadian subsidiary purchased U.S. dollars related to our repatriation of $535 million of earnings from our Canadian operations to the U.S. As a result of a decrease in the Canadian-to-U.S. dollar exchange rate while these U.S. dollars were held, we recognized a $7 million loss in 2005. The increase in the Canadian-to-U.S. dollar exchange rate from $0.7738 at December 31, 2003 to $0.8308 at December 31, 2004 resulted in a $22 million gain. The increase in the Canadian-to-U.S. dollar exchange rate from $0.6331 at December 31, 2002 to $0.7738 at December 31, 2003 resulted in a $69 million gain.

Change in Fair Value of Derivative Financial Instruments

      The details of the changes in fair value of derivative financial instruments between 2003 and 2005 are shown in the table below.

		2005			2004			2003
		(In millions)
Change in fair value of the option embedded in debentures exchangeable into shares of Chevron Corporation common stock		$	54			58			(3	)
Ineffectiveness of commodity hedges			5			5			1
Non-qualifying commodity hedges			39			—			—
Other			(4	)		(1	)		1
	Total	$	94			62			(1	)

      The change in fair value of the option embedded in debentures exchangeable into shares of Chevron Corporation common stock decreased $4 million and increased $61 million in 2005 and 2004, respectively. The value of this option is driven primarily by the price of Chevron Corporation’s common stock. Generally, as the price of Chevron Corporation’s common stock increases, we recognize a larger loss on the option.

      In 2005, we recognized a $39 million loss on certain oil derivative financial instruments that no longer qualified for hedge accounting because the hedged production exceeded actual and projected production under these contracts. The lower than expected production was caused primarily by hurricanes that affected offshore production in the Gulf of Mexico.

Other Income, Net

      The following schedule includes the components of other income between 2003 and 2005.

		2005			2004		2003
		(In millions)
Interest and dividend income		$	95			45		33
Gain on sales of non-oil and gas property and equipment			150			33		(3	)
Loss on derivative financial instruments			(48	)		—		—
Other			(1	)		25		7
	Total	$	196			103		37

      2005 vs. 2004 Other income increased $93 million in 2005. Other income increased $117 million due to gains resulting from sales of certain non-oil and gas properties in 2005. Interest and dividend income increased $50 million in 2005 primarily due to an increase in cash and short-term investment balances and higher interest rates. The 2005 loss on derivative financial instruments resulted primarily from a

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$55 million loss on certain commodity hedges that no longer qualified for hedge accounting and were settled prior to the end of their original term. These hedges related to U.S. and Canadian oil production from properties sold as part of our 2005 property divestiture program. This loss was partially offset by a $7 million gain related to interest rate swaps that were settled prior to the end of their original term in conjunction with the early redemption of the $400 million 6.75% senior notes in 2005.

      2004 vs. 2003 Other income increased $66 million in 2004. Other income increased $36 million due to gains resulting from sales of certain non-oil and gas properties in 2004. Interest and dividend income increased $12 million in 2004 due to an increase in cash and short-term investment balances.

Income Taxes

      2005 vs. 2004 Our 2005 effective financial tax rate was 36% compared to 34% in 2004. Both rates approximated the 35% statutory federal tax rate. Income taxes were reduced by $14 million and $36 million in 2005 and 2004, respectively, related to Canadian statutory rate reductions. The 2005 rate also included $28 million of additional tax related to our repatriation of $545 million, substantially all of which was Canadian earnings from our Canadian subsidiary, to the U.S.

      2004 vs. 2003 Our 2004 effective financial tax rate attributable to continuing operations was 34% compared to 23% in 2003. Both years’ rates were affected by the incremental effect of state income taxes offset by the tax benefits of certain foreign deductions. In addition, both the 2004 and 2003 rates included benefits from Canadian statutory rate reductions of $36 million and $218 million, respectively. Excluding the effect of the 2003 Canadian rate reduction, the 2003 effective tax rate would have been 33%.

Cumulative Effect of Change in Accounting Principle

      Effective January 1, 2003, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, and recorded a cumulative-effect-type adjustment for an increase to net earnings of $16 million net of deferred taxes of $10 million.

      In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (“SAB No. 106”) to provide guidance regarding the interaction of SFAS No. 143 with the full cost method of accounting for oil and gas properties. Specifically, SAB No. 106 clarifies the manner in which the full cost ceiling test and DD&A should be calculated in accordance with the provisions of SFAS No. 143. We adopted SAB No. 106 in the fourth quarter of 2004. However, this adoption did not materially impact our full cost ceiling test calculation or DD&A for 2004.

Capital Resources, Uses and Liquidity

      The following discussion of capital resources and liquidity should be read in conjunction with the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data”.

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Sources and Uses of Cash

      At December 31, 2005, our unrestricted cash and cash equivalents and short-term investments totaled $2.3 billion. During 2005, 2004 and 2003, such balances increased $167 million, $846 million and $981 million, respectively. The following table summarizes the changes in our cash and cash equivalents from 2003 to 2005. Additional discussion of the key elements contributing to these changes follows the table.

		2005			2004			2003
		(In millions)
Cash provided by (used in):
	Operating activities	$	5,612			4,816			3,768
	Investing activities		(1,652	)		(3,634	)		(2,773	)
	Financing activities		(3,543	)		(1,001	)		(414	)
Effect of exchange rate changes			37			39			59
Net increase in cash and cash equivalents		$	454			220			640
Cash and cash equivalents at end of year		$	1,606			1,152			932
Short-term investments at end of year		$	680			967			341

Cash Flows from Operating Activities

      Net cash provided by operating activities (“operating cash flow”) is our primary source of capital and liquidity. Operating cash flow is largely affected by our net earnings, excluding large non-cash expenses such as depreciation, depletion and amortization and deferred income tax expense. As a result, our operating cash flow increased in 2005 and 2004 compared to the previous years due to increases in net earnings, as discussed in the “Results of Operations” section of this report.

Cash Flows from Investing Activities

      Capital Expenditures. The increases in operating cash flow enabled us to invest larger amounts in capital projects. As a result, our capital expenditures increased 32% to $4.1 billion in 2005. The majority of this increase related to our expenditures for the acquisition, drilling or development of oil and gas properties, which totaled $3.9 billion in 2005. Increased drilling activities in the Barnett Shale, the approximately $200 million acquisition of Iron River acreage in Canada and the $74 million purchase of the Serpentina FPSO in offshore Equatorial Guinea were large contributors to the increase. Significant cost escalation and the weaker U.S. dollar also caused our expenditures to increase from 2004 to 2005.

      Capital expenditures also increased 20% to $3.1 billion in 2004. Our April 2003 merger with Ocean Energy was the primary cause of this increase because 2003 only included eight months of capital activity related to the Ocean Energy properties acquired.

      Proceeds from Sales of Property and Equipment. In 2005, we generated $2.2 billion in proceeds from sales. This consisted primarily of $2.0 billion in pre-tax proceeds, net of all purchase price adjustments, related to the sale of non-core oil and gas properties. In addition, we sold non-core midstream assets for $0.2 billion in pre-tax proceeds. Net of related income taxes, these proceeds were $1.8 billion for oil and gas properties and $0.1 billion for midstream assets.

      Proceeds from the sale of property and equipment were $95 million and $179 million in 2004 and 2003, respectively. These amounts consisted primarily of proceeds related to the sale of non-core midstream assets.

      Changes in Short-Term Investments. To maximize our income on available cash balances, we invest in highly liquid, short-term investments. The purchase and sale of these short-term investments will cause

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cash and cash equivalents to decrease and increase, respectively. Short-term investment balances decreased $287 million in 2005, increased $626 million in 2004 and increased $341 million in 2003.

Cash Flows from Financing Activities

      Net Debt Repayments. Our net debt retirements were $1.3 billion, $1.0 billion and $0.5 billion in 2005, 2004 and 2003, respectively. The 2005 amount includes $0.8 billion related to the retirement of the zero coupon convertible debentures and the $400 million 6.75% notes due March 2011 before their scheduled maturity dates. The 2004 amount includes $635 million for the payment of the outstanding balance under our $3 billion term loan credit facility. The 2003 amount includes payments on certain debt instruments assumed in the April 2003 Ocean Energy merger.

      Stock Repurchases. We are utilizing operating cash flow and proceeds from the sale of non-core oil and gas properties to repurchase our common stock. In August 2005, we completed the stock repurchase program announced September 27, 2004. Under this program, we repurchased 44.6 million shares at a total cost of $2.1 billion in 2005, and 5.0 million shares at a total cost of $189 million in 2004. Subsequent to the completion of the program announced in 2004, we announced on August 3, 2005 a new program. Under this new program, we may repurchase up to 50 million shares by the end of 2007. In 2005, we purchased 2.2 million shares at a total cost of $134 million under this new repurchase program.

      Dividends. Our common stock dividends were $136 million, $97 million and $39 million in 2005, 2004 and 2003, respectively. We also paid $10 million of preferred stock dividends in 2005, 2004 and 2003. The 2005 increase in common stock dividends was primarily related to a 50% increase in the dividend rate in the first quarter of 2005, partially offset by a decrease in outstanding shares due to share repurchases. The 2004 increase in common stock dividends resulted from a 100% increase in the dividend rate in the first quarter of 2004 and an increase in outstanding shares due to the April 2003 Ocean Energy merger.

      Issuance of Common Stock. Proceeds from the issuance of our common stock were $124 million, $268 million and $155 million in 2005, 2004 and 2003, respectively. These proceeds were derived primarily from the exercise of employee stock options.

Liquidity

      Historically, our primary source of capital and liquidity has been operating cash flow. Additionally, we maintain a revolving line of credit and a commercial paper program which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity securities and long-term debt. We expect the combination of these sources of capital will be more than adequate to fund future capital expenditures, common stock repurchases, and other contractual commitments as discussed later in this section.

Operating Cash Flow

      Our operating cash flow has increased nearly 50% since 2003, reaching a total of $5.6 billion in 2005. Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. We expect operating cash flow to continue to be our primary source of liquidity.

Credit Lines

      Another source of liquidity is our $1.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility includes (i) a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million and (ii) a $1 billion sublimit for the issuance of letters of credit, including letters of credit under the Canadian subfacility. Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to

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twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As of December 31, 2005, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of December 31, 2005, net of $310 million of outstanding letters of credit, was approximately $1.2 billion.

      The Senior Credit Facility matures on April 8, 2010, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 8 anniversary date, we have the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. We are working to obtain lender approval to extend the current maturity date of April 8, 2010 to April 8, 2011. If successful, this maturity date extension will be effective April 7, 2006, provided we have not experienced a “material adverse effect,” as defined in the Senior Credit Facility agreement, at that date.

      The Senior Credit Facility contains only one material financial covenant. This covenant requires our ratio of total funded debt to total capitalization to be less than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in our consolidated financial statements. As defined in the agreement, total funded debt excludes the debentures that are exchangeable into shares of Chevron Corporation common stock. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of December 31, 2005, our ratio as calculated pursuant to this covenant was 27.0%.

      Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our Senior Credit Facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the Senior Credit Facility is not conditioned on the absence of a material adverse effect.

      We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program may not exceed $725 million. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between seven and 90 days, although it can have a maturity of up to 365 days. We had no commercial paper debt outstanding at December 31, 2005.

Debt Ratings

      We receive debt ratings from the major ratings agencies in the United States. In determining our debt ratings, the agencies consider a number of items including, but not limited to, debt levels, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Liquidity, asset quality, cost structure, reserve mix, and commodity pricing levels are also considered by the rating agencies. Our current debt ratings are BBB with a positive outlook by Standard & Poor’s, Baa2 with a stable outlook by Moody’s and BBB with a stable outlook by Fitch.

      There are no “rating triggers” in any of our contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Our cost of borrowing under our Senior Credit Facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs for the Senior Credit Facility from LIBOR plus 70 basis points to a new rate of LIBOR plus 87.5 basis points. A ratings downgrade could also adversely impact our ability to economically access future debt markets. As of December 31, 2005, we were not aware of any potential ratings downgrades being contemplated by the rating agencies.

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Capital Expenditures

      In February 2006, we announced our 2006 capital expenditures budget. Our 2006 capital expenditures are expected to range from $5.0 billion to $5.2 billion. This represents the largest planned use of our 2006 operating cash flow, and is 20% to 30% higher than the 2005 capital expenditures. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if oil and natural gas prices fluctuate from current estimates, we could choose to defer a portion of these planned 2006 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2006 to achieve the desired balance between sources and uses of liquidity. Based upon current oil and natural gas price expectations for 2006, we anticipate that our capital resources will be more than adequate to fund 2006 capital expenditures.

Common Stock Repurchase Program

      During 2006 and 2007, we may repurchase up to 47.8 million additional shares in conjunction with our stock repurchase program announced in August 2005. We anticipate the shares would be repurchased with operating cash flow. The stock repurchase program may be discontinued at any time.

Contractual Obligations

      A summary of our contractual obligations as of December 31, 2005, is provided in the following table.

		Payments Due By Year
												After
		2006		2007		2008		2009		2010		2010		Total
		(In millions)
Long-term debt(1)		$	673		400		762		177		—		4,625		6,637
Interest expense(2)			453		422		401		363		345		4,195		6,179
Drilling and facility obligations(3)			666		261		180		118		93		—		1,318
Asset retirement obligations(4)			50		38		50		50		66		414		668
Firm transportation agreements(5)			102		89		66		52		38		131		478
Lease obligations(6)			53		51		46		42		34		203		429
Other			24		20		—		—		—		—		44
	Total	$	2,021		1,281		1,505		802		576		9,568		15,753

(1)	Long-term debt amounts represent scheduled maturities of our debt obligations at December 31, 2005, excluding $18 million of fair value adjustments included in the carrying value of debt. In addition, $387 million of letters of credit that have been issued by commercial banks on our behalf are excluded from the table. The majority of these letters of credit, if funded, would become borrowings under our revolving credit facility. Most of these letters of credit have been granted by financial institutions to support our international and Canadian drilling commitments.
(2)	Interest expense amounts represent the scheduled fixed-rate and variable-rate cash payments related to our long-term debt. Interest on our variable-rate debt was estimated based upon expected future rates at December 31, 2005.
(3)	Drilling and facility obligations represent contractual agreements with third party service providers to procure drilling rigs and other drilling related services for developmental and exploratory drilling.
(4)	Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These costs are recorded as liabilities on our December 31, 2005 balance sheet.
(5)	Firm transportation agreements represent “ship or pay” arrangements whereby we have committed to ship certain volumes of oil, gas and NGLs for a fixed transportation fee. We have entered into these

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	agreements to aid the movement of our gas production to market. We expect to have sufficient production to utilize the majority of these transportation services.
(6)	Lease obligations consist of operating leases for office and equipment, an offshore platform spar and an FPSO. Office and equipment leases represent non-cancelable leases for office space and equipment used in our daily operations.

We have an offshore platform spar that is being used in the development of the Nansen field in the Gulf of Mexico. This spar is subject to a 20-year lease and contains various options whereby we may purchase the lessors’ interests in the spars. We have guaranteed that the spar will have a residual value at the end of the term equal to at least 10% of the fair value of the spar at the inception of the lease. The total guaranteed value is $14 million in 2022. However, such amount may be reduced under the terms of the lease agreements. In 2005, we sold our interests in the Boomvang field in the Gulf of Mexico, which has a spar lease with terms similar to those of the Nansen lease. As a result of the sale, we are subleasing the Boomvang Spar. The table above does not include any amounts related to the Boomvang spar lease. However, if the sublessee defaults on its obligation, we would be required to continue making the lease payments and any guaranteed payment required at the end of the term.

We have an FPSO that is being used in the Panyu project offshore China. This FPSO lease term expires in September 2009.

Pension Funding and Estimates

      Funded Status. As compared to the “projected benefit obligation,” our qualified and nonqualified defined benefit plans were underfunded by $133 million and $132 million at December 31, 2005 and 2004, respectively. A detailed reconciliation of the 2005 changes to our underfunded status is included in Note 11 to the accompanying consolidated financial statements. Of the $133 million underfunded status at the end of 2005, $126 million is attributable to various nonqualified defined benefit plans which have no plan assets. However, we have established certain trusts to fund the benefit obligations of such nonqualified plans. As of December 31, 2005, these trusts had investments with a fair value of $59 million. The value of these trusts is included in noncurrent other assets in our accompanying consolidated balance sheets.

      As compared to the “accumulated benefit obligation,” our qualified defined benefit plans were overfunded by $37 million at December 31, 2005. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. Our current intentions are to provide sufficient funding in future years to ensure the accumulated benefit obligation remains fully funded. The actual amount of contributions required during this period will depend on investment returns from the plan assets. Required contributions also depend upon changes in actuarial assumptions made during the same period, particularly the discount rate used to calculate the present value of the accumulated benefit obligation. For 2006, we expect our contributions to the plan to be less than $10 million.

      Pension Estimate Assumptions. Our pension expense is recognized on an accrual basis over employees’ approximate service periods and is generally calculated independent of funding decisions or requirements. We recognized expense for our defined benefit pension plans of $26 million, $26 million and $35 million in 2005, 2004 and 2003, respectively. We estimate that our pension expense will approximate $31 million in 2006.

      The calculation of pension expense and pension liability requires the use of a number of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. We believe that the two most critical assumptions affecting pension expense and liabilities are the expected long-term rate of return on plan assets and the assumed discount rate.

      We assumed that our plan assets would generate a long-term weighted average rate of return of 8.40% and 8.34% at December 31, 2005 and 2004, respectively. We developed these expected long-term rate of return assumptions by evaluating input from external consultants and economists as well as long-term

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inflation assumptions. The expected long-term rate of return on plan assets is based on a target allocation of investment types in such assets. The target investment allocation for our plan assets is 50% U.S. large cap equity securities; 15% U.S. small cap equity securities, equally allocated between growth and value; 15% international equity securities, equally allocated between growth and value; and 20% debt securities. We expect our long-term asset allocation on average to approximate the targeted allocation. We regularly review our actual asset allocation and periodically rebalance the investments to the targeted allocation when considered appropriate.

      Pension expense increases as the expected rate of return on plan assets decreases. A decrease in our long-term rate of return assumption of 100 basis points (from 8.40% to 7.40%) would increase the expected 2006 pension expense by $5 million.

      We discounted our future pension obligations using a weighted average rate of 5.72% at December 31, 2005, compared to 5.74% at December 31, 2004. The discount rate is determined at the end of each year based on the rate at which obligations could be effectively settled. This rate is based on high-quality bond yields, after allowing for call and default risk. We consider high quality corporate bond yield indices, such as Moody’s Aa, when selecting the discount rate.

      The pension liability and future pension expense both increase as the discount rate is reduced. Lowering the discount rate by 25 basis points (from 5.72% to 5.47%) would increase our pension liability at December 31, 2005, by $23 million, and increase estimated 2006 pension expense by $3 million.

      At December 31, 2005, we had unrecognized actuarial losses of $195 million which will be recognized as a component of pension expense in future years. These losses are primarily due to reductions in the discount rate since 2001. We estimate that approximately $12 million and $11 million of the unrecognized actuarial losses will be included in pension expense in 2006 and 2007, respectively. The $12 million estimated to be recognized in 2006 is a component of the total estimated 2006 pension expense of $31 million referred to earlier in this section.

      Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in our defined benefit pension plans will impact future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future.

      On November 10, 2005, the Financial Accounting Standards Board (“FASB”) announced that it expects to make significant changes in the disclosure and measurement rules for pension benefits. These expected changes will be made in two stages. The first stage of rule changes are expected to be issued in 2006. These rule changes are expected to require companies to recognize a pension asset or liability equal to the difference between the projected benefit obligation and the fair value of the plan assets. As a result, unrecognized actuarial losses and other unrecognized costs that are used to calculate the pension asset or liability under current rules will be recognized immediately as an adjustment to stockholders’ equity. Had these rule changes been effective December 31, 2005, our stockholders’ equity would have decreased less than 1%. The second stage of this project is expected to take several years before rule changes are presented.

Contingencies and Legal Matters

      For a detailed discussion of contingencies and legal matters, see “Item 3. Legal Proceedings” and note 12 of the accompanying consolidated financial statements.

Critical Accounting Policies and Estimates

      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known.

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      The critical accounting policies used by management in the preparation of our consolidated financial statements are those that are important both to the presentation of our financial condition and results of operations and require significant judgments by management with regard to estimates used. Our critical accounting policies and significant judgments and estimates related to those policies are described below. We have reviewed these critical accounting policies with the Audit Committee of the Board of Directors.

Full Cost Ceiling Calculations

Policy Description

      We follow the full cost method of accounting for our oil and gas properties. The full cost method subjects companies to quarterly calculations of a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties, plus the cost of properties not subject to amortization. If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense, except as discussed in the following paragraph. The ceiling limitation is imposed separately for each country in which we have oil and gas properties.

      If, subsequent to the end of the quarter but prior to the applicable financial statements being published, prices increase to levels such that the ceiling would exceed the costs to be recovered, a writedown otherwise indicated at the end of the quarter is not required to be recorded. A writedown indicated at the end of a quarter is also not required if the value of additional reserves proved up on properties after the end of the quarter but prior to the publishing of the financial statements would result in the ceiling exceeding the costs to be recovered, as long as the properties were owned at the end of the quarter. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.

Judgments and Assumptions

      The discounted present value of future net revenues for our proved oil, natural gas and NGL reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Certain of our reserve estimates are prepared or audited by outside petroleum consultants, while other reserve estimates are prepared by our engineers. See Note 15 of the accompanying consolidated financial statements.

      The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. In the past five years, annual revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 1% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of DD&A.

      While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that a 10% discount factor be used and that prices and costs in effect as of the last day of the period are held constant indefinitely. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs. Rather, they are based on such prices and costs in effect as of

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the end of each quarter when the ceiling calculation is performed. In calculating the ceiling, we adjust the end-of-period price by the effect of cash flow hedges in place. This adjustment requires little judgment as the end-of-period price is adjusted using the contract prices for our cash flow hedges. We had no such hedges outstanding at December 31, 2005.

      Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been volatile. On any particular day at the end of a quarter, prices can be either substantially higher or lower than our long-term price forecast that is a barometer for true fair value. Therefore, oil and gas property writedowns that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Derivative Financial Instruments

Policy Description

      Historically, we have used oil and gas derivative financial instruments to manage our exposure to oil and gas price volatility. We have also used interest rate swaps to manage our exposures to interest rate volatility. The interest rate swaps mitigate either the effects on interest expense for variable-rate debt instruments, or the debt fair values for fixed-rate debt. We are not involved in any speculative trading activities of derivatives. All derivatives requiring balance sheet recognition are recognized on the balance sheet at their fair value. At December 31, 2005, the only derivative financial instruments outstanding consisted of interest rate swaps.

      Prior to December 31, 2005, a substantial portion of our derivatives consisted of contracts that hedged the price of future oil and natural gas production. At inception, these derivative contracts were cash flow hedges that qualified for hedge accounting treatment. Therefore, while fair values of such hedging instruments are estimated as of the end of each reporting period, the changes in the fair values attributable to the effective portion of these hedging instruments are not included in our consolidated results of operations. Instead, the changes in fair value of the effective portion of these hedging instruments, net of tax, are recorded directly to stockholders’ equity until the hedged oil or natural gas quantities are produced. The ineffective portion of these hedging instruments is included in our consolidated results of operations.

      To qualify for hedge accounting treatment, we designate our cash flow hedge instruments as such on the date the derivative contract is entered into or the date of a business combination which includes cash flow hedge instruments. Additionally, we document all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking various hedge transactions. We also assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. If we fail to meet the requirements for using hedge accounting treatment, changes in fair value of these hedging instruments would not be recorded directly to equity but in the consolidated results of operations.

Judgments and Assumptions

      The estimates of the fair values of our commodity derivative contracts require substantial judgment. For these contracts, we obtain forward price and volatility data for all major oil and gas trading points in North America from independent third parties. These forward prices are compared to the price parameters contained in the hedge agreements. The resulting estimated future cash inflows or outflows over the lives of the hedge contracts are discounted using LIBOR and money market futures rates for the first year and money market futures and swap rates thereafter. In addition, we estimate the option value of price floors and price caps using an option pricing model. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices, regional price differentials

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and interest rates. Fair values of our other derivative contracts require less judgment to estimate and are primarily based on quotes from independent third parties such as counterparties or brokers.

      Quarterly changes in estimates of fair value have only a minimal impact on our liquidity, capital resources or results of operations, as long as the derivative contracts qualify for treatment as a hedge. However, settlements of derivative contracts do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative contracts, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding the effects that changes in market prices will have on our derivative financial instruments, net earnings and cash flow from operations is included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk”.

Business Combinations

Policy Description

      We have grown substantially during recent years through acquisitions of other oil and natural gas companies. Most of these acquisitions have been accounted for using the purchase method of accounting, and recent accounting pronouncements require that all future acquisitions will be accounted for using the purchase method.

      Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company’s assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill. Goodwill is assessed for impairment at least annually.

Judgments and Assumptions

      There are various assumptions we make in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, we prepare estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by our engineers and that of outside consultants. The judgments associated with these estimated reserves are described earlier in this section in connection with the full cost ceiling calculation.

      However, there are factors involved in estimating the fair values of acquired oil, natural gas and NGL properties that require more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies end-of-period price and cost information to the reserves to arrive at the ceiling amount. By contrast, the fair value of reserves acquired in a business combination must be based on our estimates of future oil, natural gas and NGL prices. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.

      We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriate at the time of the business combination based upon our cost of capital.

      We also apply these same general principles to estimate the fair value of unproved properties acquired in a business combination. These unproved properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by what we

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consider to be an appropriate risk-weighting factor in each particular instance. It is common for the discounted future net revenues of probable and possible reserves to be reduced by factors ranging from 30% to 80% to arrive at what we consider to be the appropriate fair values.

      Generally, in our business combinations, the determination of the fair values of oil and gas properties requires much more judgment than the fair values of other assets and liabilities. The acquired companies commonly have long-term debt that we assume in the acquisition, and this debt must be recorded at the estimated fair value as if we had issued such debt. However, significant judgment on our behalf is usually not required in these situations due to the existence of comparable market values of debt issued by peer companies.

      Except for the 2002 Mitchell merger, our mergers and acquisitions have involved other entities whose operations were predominantly in the area of exploration, development and production activities related to oil and gas properties. However, in addition to exploration, development and production activities, Mitchell’s business also included substantial marketing and midstream activities. Therefore, a portion of the Mitchell purchase price was allocated to the fair value of Mitchell’s marketing and midstream facilities and equipment. This consisted primarily of natural gas processing plants and natural gas pipeline systems.

      The Mitchell midstream assets primarily served gas producing properties that we also acquired from Mitchell. Therefore, certain of the assumptions regarding future operations of the gas producing properties were also integral to the value of the midstream assets. For example, future quantities of natural gas estimated to be processed by natural gas processing plants were based on the same estimates used to value the proved and unproved gas producing properties. Future expected prices for marketing and midstream product sales were also based on price cases consistent with those used to value the oil and gas producing assets acquired from Mitchell. Based on historical costs and known trends and commitments, we also estimated future operating and capital costs of the marketing and midstream assets to arrive at estimated future cash flows. These cash flows were discounted at rates consistent with those used to discount future net cash flows from oil and gas producing assets to arrive at our estimated fair value of the marketing and midstream facilities and equipment.

      In addition to the valuation methods described above, we perform other quantitative analyses to support the indicated value in any business combination. These analyses include information related to comparable companies, comparable transactions and premiums paid.

      In a comparable companies analysis, we review the public stock market trading multiples for selected publicly traded independent exploration and production companies with comparable financial and operating characteristics. Such characteristics are market capitalization, location of proved reserves and the characterization of those reserves that we deem to be similar to those of the party to the proposed business combination. We compare these comparable company multiples to the proposed business combination company multiples for reasonableness.

      In a comparable transactions analysis, we review certain acquisition multiples for selected independent exploration and production company transactions and oil and gas asset packages announced recently. We compare these comparable transaction multiples to the proposed business combination transaction multiples for reasonableness.

      In a premiums paid analysis, we use a sample of selected independent exploration and production company transactions in addition to selected transactions of all publicly traded companies announced recently, to review the premiums paid to the price of the target one day, one week and one month prior to the announcement of the transaction. We use this information to determine the mean and median premiums paid and compare them to the proposed business combination premium for reasonableness.

      While these estimates of fair value for the various assets acquired and liabilities assumed have no effect on our liquidity or capital resources, they can have an effect on the future results of operations. Generally, the higher the fair value assigned to both the oil and gas properties and non-oil and gas properties, the lower future net earnings will be as a result of higher future depreciation, depletion and amortization expense. Also, a higher fair value assigned to the oil and gas properties, based on higher

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future estimates of oil and gas prices, will increase the likelihood of a full cost ceiling writedown in the event that subsequent oil and gas prices drop below our price forecast that was used to originally determine fair value. A full cost ceiling writedown would have no effect on our liquidity or capital resources in that period because it is a noncash charge, but it would adversely affect results of operations. As discussed in the Capital Resources, Uses and Liquidity section of this report, in calculating our debt-to-capitalization ratio under our credit agreement, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling property impairments or goodwill impairments.

      Our estimates of reserve quantities are one of the many estimates that are involved in determining the appropriate fair value of the oil and gas properties acquired in a business combination. As previously disclosed in our discussion of the full cost ceiling calculations, during the past five years, our annual revisions to our reserve estimates have averaged approximately 1%. As discussed in the preceding paragraphs, there are numerous estimates in addition to reserve quantity estimates that are involved in determining the fair value of oil and gas properties acquired in a business combination. The inter-relationship of these estimates makes it impractical to provide additional quantitative analyses of the effects of changes in these estimates.

Valuation of Goodwill

Policy Description

      Goodwill is tested for impairment at least annually. This requires us to estimate the fair values of our own assets and liabilities in a manner similar to the process described above for a business combination. Therefore, considerable judgment similar to that described above in connection with estimating the fair value of an acquired company in a business combination is also required to assess goodwill for impairment.

Judgments and Assumptions

      Generally, the higher the fair value assigned to both the oil and gas properties and non-oil and gas properties, the lower goodwill would be. A lower goodwill value decreases the likelihood of an impairment charge. However, unfavorable changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.

      Due to the inter-relationship of the various estimates involved in assessing goodwill for impairment, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates, other than to note the historical average changes in our reserve estimates previously set forth.

Recently Issued Accounting Standards Not Yet Adopted

      In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), “Share-Based Payment”, (“SFAS No. 123(R)”) which is a revision of SFAS No. 123 and supersedes APB Opinion No. 25 regarding stock-based employee compensation plans. APB Opinion No. 25 requires recognition of compensation expense only if the current market price of the underlying stock exceeded the stock option exercise price on the date of grant. Additionally, SFAS No. 123 established fair value-based accounting for stock-based employee compensation plans but allowed pro forma disclosure as an alternative to financial statement recognition. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant, and to be expensed over the applicable vesting period. Also, pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. We will adopt the provisions of SFAS No. 123(R) in the first quarter of 2006 using the modified prospective method. Under this method, we will recognize compensation expense for all stock-based awards granted or modified on or after January 1, 2006, as well as any previously granted awards that are not fully vested as of January 1, 2006. Compensation expense will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS No. 123. Based on our current estimates of the amount of 2006 stock option grants and the various assumptions used to estimate the fair value of these

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stock option grants, we expect stock option expense, net of related capitalization in accordance with the full cost method of accounting for oil and gas properties, will be approximately $35 million. No retroactive or cumulative effect adjustments will be recorded upon adoption.

2006 Estimates

      The forward-looking statements provided in this discussion are based on our examination of historical operating trends, the information which was used to prepare the December 31, 2005 reserve reports and other data in our possession or available from third parties. These forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for our oil, natural gas and NGLs during 2006 will be substantially similar to those of 2005, unless otherwise noted. We make reference to the “Disclosure Regarding Forward-Looking Statements” at the beginning of this report. Amounts related to Canadian operations have been converted to U.S. dollars using a projected average 2006 exchange rate of $0.87 U.S. dollar to $1.00 Canadian dollar.

Oil, Gas and NGL Production and Prices

      Set forth in the following paragraphs are individual estimates of oil, gas and NGL production for 2006. On a combined basis, we estimate our 2006 oil, gas and NGL production will total approximately 217 MMBoe. Of this total, approximately 95% is estimated to be produced from reserves classified as “proved” at December 31, 2005.

Oil Production

      Oil production in 2006 is expected to total approximately 58 MMBbls. Of this total, approximately 99% is estimated to be produced from reserves classified as “proved” at December 31, 2005. The expected production by area is as follows:

	(MMBbls)
United States Onshore		11
United States Offshore		9
Canada		14
International		24

     Oil Prices

      We have not fixed the price we will receive on any of our 2006 oil production. Our 2006 average prices for each of our areas are expected to differ from the NYMEX price as set forth in the following table. The NYMEX price is the monthly average of settled prices on each trading day for benchmark West Texas Intermediate crude oil delivered at Cushing, Oklahoma.

	Expected Range of Oil Prices
	as a % of NYMEX Price
United States Onshore		86% to 94%
United States Offshore		86% to 94%
Canada		65% to 75%
International		80% to 88%

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Gas Production

      Gas production in 2006 is expected to total approximately 820 Bcf. Of this total, approximately 94% is estimated to be produced from reserves classified as “proved” at December 31, 2005. The expected production by area is as follows:

	(Bcf)
United States Onshore		492
United States Offshore		75
Canada		243
International		10

Gas Prices — Fixed

      The price for approximately 2% of our estimated 2006 natural gas production has been fixed via various fixed-price physical delivery contracts. The following table includes information on this fixed-price production by area. Where necessary, the prices have been adjusted for certain transportation costs that are netted against the prices recorded by us, and the prices have also been adjusted for the expected Btu content of the gas hedged.

	Mcf/Day		Price/Mcf		Months of Production
Canada		38,578	$	3.33		Jan - Dec
International		12,000	$	2.15		Jan - Dec

Gas Prices — Floating

      For the natural gas production for which prices have not been fixed, our 2006 average prices for each of our areas are expected to differ from the NYMEX price as set forth in the following table. The NYMEX price is determined to be the first-of-month South Louisiana Henry Hub price index as published monthly in Inside FERC.

	Expected Range of Gas Prices
	as a % of NYMEX Price
United States Onshore		74% to  84%
United States Offshore		92% to 102%
Canada		80% to  90%
International		50% to  70%

NGL Production

      We expect our 2006 production of NGLs to total approximately 22 MMBbls. Of this total, 97% is estimated to be produced from reserves classified as “proved” at December 31, 2005. The expected production by area is as follows:

	(MMBbls)
United States Onshore		17
United States Offshore		1
Canada		4

Marketing and Midstream Revenues and Expenses

      Marketing and midstream revenues and expenses are derived primarily from our natural gas processing plants and natural gas transport pipelines. These revenues and expenses vary in response to several factors. The factors include, but are not limited to, changes in production from wells connected to the pipelines and related processing plants, changes in the absolute and relative prices of natural gas and

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NGLs, provisions of the contract agreements and the amount of repair and workover activity required to maintain anticipated processing levels.

      These factors, coupled with uncertainty of future natural gas and NGL prices, increase the uncertainty inherent in estimating future marketing and midstream revenues and expenses. Given these uncertainties, we estimate that 2006 marketing and midstream revenues will be between $1.74 billion and $2.20 billion, and marketing and midstream expenses will be between $1.38 billion and $1.80 billion.

Production and Operating Expenses

      Our production and operating expenses include lease operating expenses, transportation costs and production taxes. These expenses vary in response to several factors. Among the most significant of these factors are additions to or deletions from the property base, changes in the general price level of services and materials that are used in the operation of the properties, the amount of repair and workover activity required and changes in production tax rates. Oil, natural gas and NGL prices also have an effect on lease operating expenses and impact the economic feasibility of planned workover projects.

      Given these uncertainties, we estimate that 2006 lease operating expenses (including transportation costs) will be between $1.43 billion and $1.50 billion and production taxes will be between 3.25% and 3.75% of consolidated oil, natural gas and NGL revenues.

DD&A

      The 2006 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that will be added from drilling or acquisition efforts in 2006 compared to the costs incurred for such efforts, and the revisions to our year-end 2005 reserve estimates that, based on prior experience, are likely to be made during 2006.

      Given these uncertainties, we expect oil and gas property related DD&A rate will be between $9.30 per Boe and $9.50 per Boe. Based on these DD&A rates and the production estimates set forth earlier, oil and gas property related DD&A expense for 2006 is expected to be between $2.02 billion and $2.06 billion.

      Additionally, we expect depreciation and amortization expense related to non-oil and gas property fixed assets to total between $170 million and $180 million.

Accretion of Asset Retirement Obligation

      The 2006 accretion of asset retirement obligation is expected to be between $48 million and $53 million.

G&A

      Our G&A includes employee compensation and benefits costs and the costs of many different goods and services used in support of our business. G&A varies with the level of our operating activities and the related staffing and professional services requirements. In addition, employee compensation and benefits costs vary due to various market factors that affect the level and type of compensation and benefits offered to employees. Also, goods and services are subject to general price level increases or decreases. Therefore, significant variances in any of these factors from current expectations could cause actual G&A to vary materially from the estimate.

      Given these limitations, consolidated G&A in 2006 is expected to be between $360 million and $380 million. This estimate includes $35 million of expenses related to restricted stock compensation costs, net of related capitalization in accordance with the full cost method of accounting for oil and gas properties. This estimate also includes $35 million of expenses related to stock option compensation costs, net of related capitalization.

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Reduction of Carrying Value of Oil and Gas Properties

      We follow the full cost method of accounting for our oil and gas properties described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates”. Reductions to the carrying value of our oil and gas properties are largely dependent on the success of drilling results and oil and natural gas prices at the end of our quarterly reporting periods. Due to the uncertain nature of future drilling efforts and oil and natural gas prices, we are not able to predict whether we will incur such reductions in 2006.

Interest Expense

      Future interest rates and debt outstanding have a significant effect on our interest expense. We can only marginally influence the prices we will receive in 2006 from sales of oil, natural gas and NGLs and the resulting cash flow. These factors increase the margin of error inherent in estimating future interest expense. Other factors which affect interest expense, such as the amount and timing of capital expenditures, are within our control.

      Based on the information related to interest expense set forth below and assuming no material changes in our expected level of indebtedness or prevailing interest rates, we expect our 2006 interest expense (net of amounts capitalized) will be between $385 million and $395 million. Details of this estimate are discussed in the following paragraphs.

      The interest expense in 2006 related to our fixed-rate debt, including net accretion of related discounts, will be approximately $410 million. This fixed-rate debt removes the uncertainty of future interest rates from some, but not all, of our long-term debt. Our floating rate debt is discussed in the following paragraphs.

      We have various debt instruments which have been converted to floating rate debt through the use of interest rate swaps. Our floating rate debt is as follows:

Debt Instrument	Notional Amount			Floating Rate
	(In millions)
2.75% notes due in August 2006	$	500		LIBOR less 26.8 basis points
6.55% senior notes due in August 2006	$	172	(1)	Banker’s Acceptance plus 340 basis points
4.375% senior notes due in October 2007	$	400		LIBOR plus 40 basis points

(1)  Converted from $200 million Canadian dollars at a Canadian-to-U.S. dollar exchange rate of $0.8577 at December 31, 2005.

      Based on future LIBOR rates as of January 31, 2006, interest expense on our floating rate debt, including net amortization of premiums, is expected to total between $35 million and $45 million in 2006.

      Our interest expense totals include payments of facility and agency fees, amortization of debt issuance costs, the effect of interest rate swaps not accounted for as hedges, and other miscellaneous items not related to the debt balances outstanding. We expect between $5 million and $15 million of such items to be included in 2006 interest expense. Also, we expect to capitalize between $65 million and $75 million of interest during 2006.

Effects of Changes in Foreign Currency Rates

      Foreign currency gains or losses are not expected to be material in 2006.

Other Revenues

      Our other revenues in 2006 are expected to be between $155 million and $175 million.

      We maintain a comprehensive insurance program that includes coverage for physical damage to our offshore facilities caused by hurricanes. Our insurance program also includes substantial business

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interruption coverage which we expect to utilize to recover costs associated with the suspended production related to hurricanes that struck the Gulf of Mexico in the third quarter of 2005. Under the terms of the insurance program, we are entitled to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil and natural gas prices. Also, the terms of the insurance include a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible. Based on current estimates of physical damage and the anticipated length of time we will have production suspended, we expect our policy settlements will exceed repair costs and deductible amounts. As a result, 2006 and 2007 other revenues are expected to include more than $150 million for anticipated insurance proceeds in excess of repair costs. This estimate is dependent upon several variables, including the actual amount of time that production is suspended, the actual prices in effect while production is suspended and the timing of collections of insurance proceeds. Based on current estimates of the timing of collections of insurance proceeds, we expect 2006 other revenues will include $50 million to $70 million for anticipated insurance proceeds, with the balance to be recorded in 2007. Significant variances in any of these factors from current estimates could cause actual 2006 other revenues to vary materially from the estimate.

Income Taxes

      Our financial income tax rate in 2006 will vary materially depending on the actual amount of financial pre-tax earnings. The tax rate for 2006 will be significantly affected by the proportional share of consolidated pre-tax earnings generated by U.S., Canadian and International operations due to the different tax rates of each country. There are certain tax deductions and credits that will have a fixed impact on 2006 income tax expense regardless of the level of pre-tax earnings that are produced.

      Given the uncertainty of pre-tax earnings, we expect our consolidated financial income tax rate in 2006 will be between 25% and 45%. The current income tax rate is expected to be between 20% and 30%. The deferred income tax rate is expected to be between 5% and 15%. Significant changes in estimated capital expenditures, production levels of oil, gas and NGLs, the prices of such products, marketing and midstream revenues, or any of the various expense items could materially alter the effect of the aforementioned tax deductions and credits on the 2006 financial income tax rates.

Year 2006 Potential Capital Sources, Uses and Liquidity

Capital Expenditures

      Though we have completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, we do not budget, nor can we reasonably predict, the timing or size of such possible acquisitions, if any.

      Our capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected costs of the capital additions. Should actual prices received differ materially from our price expectations for future production, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2006 capital expenditures. In addition, if the actual material or labor costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from our estimates.

      Given the limitations discussed above, the following table shows expected drilling, development and facilities expenditures by geographic area. Production capital related to proved reserves relates to reserves classified as proved as of year-end 2005. Other production capital includes development drilling that does not offset currently productive units and for which there is not a certainty of continued production from a

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known productive formation. Exploration capital includes exploratory drilling to find and produce oil or gas in previously untested fault blocks or new reservoirs.

	United States		United States
	Onshore		Offshore		Canada		International		Total
	(In millions)
Production capital related to proved reserves	$	370 - $ 390	$	85 - $95	$	530 - $ 550	$	220 -  $230	$	1,205 - $1,265
Other production capital	$	1,380 - $1,430	$	120 - $130	$	570 - $ 590	$	20 - $25	$	2,090 - $2,175
Exploration capital	$	260 - $270	$	250 - $270	$	200 - $ 210	$	270 - $280	$	980 - $1,030
Total	$	2,010 - $2,090	$	455 - $495	$	1,300 - $1,350	$	510 - $535	$	4,275 - $4,470

      In addition to the above expenditures for drilling, development and facilities, we expect to spend between $255 million to $275 million on marketing and midstream assets, which include our oil pipelines, gas processing plants, CO₂ removal facilities and gas transport pipelines. We also expect to capitalize between $230 million and $240 million of G&A expenses in accordance with the full cost method of accounting and to capitalize between $65 million and $75 million of interest. We also expect to pay between $35 million and $45 million for plugging and abandonment charges and to spend between $130 million and $140 million for other non-oil and gas property fixed assets.

Other Cash Uses

      We expect to continue the policy of paying a quarterly common stock dividend. With the current $0.1125 per share quarterly dividend rate and 443 million shares of common stock outstanding as of December 31, 2005, dividends are expected to approximate $200 million. Also, we have $150 million of 6.49% cumulative preferred stock upon which we will pay $10 million of dividends in 2006.

      On August 3, 2005, we announced our intention to repurchase up to 50 million shares of our common stock. This stock repurchase program is planned to extend through 2007. During this period, shares may be purchased from time to time depending upon market conditions. We plan to repurchase shares in the open market and in privately negotiated transactions. As of February 28, 2006, we had repurchased 4.4 million shares under the program for $267 million.

Capital Resources and Liquidity

      Our estimated 2006 cash uses, including drilling and development activities and repurchase of common stock, are expected to be funded primarily through a combination of working capital (which totaled $1.3 billion at the end of 2005) and operating cash flow. The remainder, if any, could be funded with borrowings from our credit facility. We expect our combined capital resources to be more than adequate to fund anticipated capital expenditures and other cash uses for 2006 without the use of the available credit facility.

      If significant acquisitions or other unplanned capital requirements arise during the year, we could utilize our existing credit facilities and/or seek to establish and utilize other sources of financing.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

      The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

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Commodity Price Risk

      Our major market risk exposure is in the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian natural gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable for several years. See “Item 1A. Risk Factors”.

      Currently, we are largely accepting the volatility risk that oil and natural gas prices present. None of our future oil and natural gas production is subject to price swaps or collars. In addition, none of our estimated 2006 oil production, and only 2% of our estimated 2006 natural gas production, is subject to fixed-price physical delivery contracts as summarized in the table below.

	Mcf/Day		Price/Mcf		Months of Production
Canada		38,578	$	3.33		Jan - Dec
International		12,000	$	2.15		Jan - Dec

      In addition, we have fixed-price physical delivery contracts for the years 2007 through 2011 covering Canadian natural gas production ranging from seven Bcf to 14 Bcf per year. We also have fixed-price physical delivery contracts covering International gas production of four Bcf per year in 2007 and three Bcf in 2008.

     Interest Rate Risk

      At December 31, 2005, we had debt outstanding of $6.6 billion. Of this amount, $5.5 billion, or 84%, bears interest at fixed rates averaging 7.4%.

      The remaining $1.1 billion of debt outstanding bears interest at floating rates. Included in the floating-rate debt is fixed-rate debt which has been converted to floating-rate debt through interest rate swaps. Following is a table summarizing the fixed-to-floating interest rate swaps with the related debt instrument and notional amounts.

Debt Instrument	Notional Amount			Floating Rate
	(In millions)
2.75% notes due in 2006	$	500		LIBOR less 26.8 basis points
6.55% senior notes due 2006	$	172	(1)	Banker’s Acceptance plus 340 basis points
4.375% senior notes due in 2007	$	400		LIBOR plus 40 basis points

(1)  Converted from $200 million Canadian dollars at a Canadian-to-U.S. dollar exchange rate of $0.8577 at December 31, 2005.

      We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in interest rates may have on the fair value of our interest rate swap instruments. At December 31, 2005, a 10% increase in the underlying interest rates would have decreased the fair value of our interest rate swaps by $8 million.

      The above sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.

Foreign Currency Risk

      Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our December 31, 2005 balance sheet.

60

Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED

FINANCIAL STATEMENT SCHEDULES

		Page
Report of Independent Registered Public Accounting Firm			62
Consolidated Financial Statements:
	Consolidated Balance Sheets December 31, 2005 and 2004		63
	Consolidated Statements of Operations Years Ended December 31, 2005, 2004 and 2003		64
	Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss) Years Ended December 31, 2005, 2004 and 2003		65
	Consolidated Statements of Cash Flows Years Ended December 31, 2005, 2004 and 2003		66
	Notes to Consolidated Financial Statements December 31, 2005, 2004 and 2003		67

      All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.

61

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Devon Energy Corporation:

      We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Devon Energy Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

      As described in Note 1 to the consolidated financial statements, as of January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations.

      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Devon Energy Corporation’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Oklahoma City, Oklahoma

February 28, 2006

62

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

			December 31,
			2005			2004
			(In millions, except
			share data)
ASSETS
Current assets:
	Cash and cash equivalents		$	1,606			1,152
	Short-term investments			680			967
	Accounts receivable			1,601			1,320
	Deferred income taxes			158			289
	Other current assets			161			144
		Total current assets		4,206			3,872
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($2,747 and $3,187 excluded from amortization in 2005 and 2004, respectively)				34,246			32,114
Less accumulated depreciation, depletion and amortization				15,114			12,768
				19,132			19,346
Investment in Chevron Corporation common stock, at fair value				805			745
Goodwill				5,705			5,637
Other assets				425			425
	Total assets		$	30,273			30,025
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable:
		Trade	$	947			715
		Revenues and royalties due to others		666			487
	Income taxes payable			293			223
	Current portion of long-term debt			662			933
	Accrued interest payable			127			139
	Fair value of derivative financial instruments			18			399
	Current portion of asset retirement obligation			50			46
	Accrued expenses and other current liabilities			171			158
		Total current liabilities		2,934			3,100
Debentures exchangeable into shares of Chevron Corporation common stock				709			692
Other long-term debt				5,248			6,339
Fair value of derivative financial instruments				125			72
Asset retirement obligation, long-term				618			693
Other liabilities				372			366
Deferred income taxes				5,405			5,089
Stockholders’ equity:
	Preferred stock of $1.00 par value. Authorized 4,500,000 shares; issued 1,500,000 ($150 million aggregate liquidation value)			1			1
	Common stock of $0.10 par value. Authorized 800,000,000 shares; issued 443,451,000 in 2005 and 483,909,000 in 2004			44			48
	Additional paid-in capital			7,066			9,087
	Retained earnings			6,477			3,693
	Accumulated other comprehensive income			1,414			930
	Deferred compensation and other			(138	)		(85	)
	Treasury stock, at cost: 37,000 shares in 2005			(2	)		—
		Total stockholders’ equity		14,862			13,674
Commitments and contingencies (Note 12)
		Total liabilities and stockholders’ equity	$	30,273			30,025

See accompanying notes to consolidated financial statements.

63

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

			Year Ended December 31,
			2005			2004			2003
			(In millions, except per
			share amounts)
Revenues:
	Oil sales		$	2,478			2,202			1,588
	Gas sales			5,784			4,732			3,897
	NGL sales			687			554			407
	Marketing and midstream revenues			1,792			1,701			1,460
		Total revenues		10,741			9,189			7,352
Expenses and other income, net:
	Lease operating expenses			1,345			1,280			1,078
	Production taxes			335			255			204
	Marketing and midstream operating costs and expenses			1,342			1,339			1,174
	Depreciation, depletion and amortization of oil and gas properties			2,031			2,141			1,668
	Depreciation and amortization of non-oil and gas properties			160			149			125
	Accretion of asset retirement obligation			44			44			36
	General and administrative expenses			291			277			307
	Expenses related to mergers			—			—			7
	Interest expense			533			475			502
	Effects of changes in foreign currency exchange rates			(2	)		(23	)		(69	)
	Change in fair value of derivative financial instruments			94			62			(1	)
	Reduction of carrying value of oil and gas properties			212			—			111
	Other income, net			(196	)		(103	)		(35	)
		Total expenses and other income, net		6,189			5,896			5,107
Earnings before income tax expense and cumulative effect of change in accounting principle				4,552			3,293			2,245
Income tax expense:
	Current			1,238			752			193
	Deferred			384			355			321
		Total income tax expense		1,622			1,107			514
Earnings before cumulative effect of change in accounting principle				2,930			2,186			1,731
Cumulative change in accounting principle, net of tax				—			—			16
Net earnings				2,930			2,186			1,747
Preferred stock dividends				10			10			10
Net earnings applicable to common stockholders			$	2,920			2,176			1,737
Basic net earnings per share:
	Earnings before cumulative effect of change in accounting principle		$	6.38			4.51			4.12
	Cumulative change in accounting principle, net of tax			—			—			0.04
Net earnings			$	6.38			4.51			4.16
Diluted net earnings per share:
	Earnings before cumulative effect of change in accounting principle		$	6.26			4.38			4.00
	Cumulative change in accounting principle, net of tax			—			—			0.04
	Net earnings		$	6.26			4.38			4.04
Weighted average common shares outstanding:
	Basic			458			482			417
	Diluted			470			499			433

See accompanying notes to consolidated financial statements.

64

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (LOSS)

															Accumulated
												Retained			Other
									Additional			Earnings			Comprehensive			Deferred						Total
				Preferred		Common			Paid-In			(Accumulated			Income			Compensation			Treasury			Stockholders’
				Stock		Stock			Capital			Deficit)			(Loss)			and Other			Stock			Equity
				(In millions)
Balance as of December 31, 2002				$	1		31			5,163			(84	)		(267	)		(3	)		(188	)		4,653
Comprehensive income:
	Net earnings				—		—			—			1,747			—			—			—			1,747
	Other comprehensive income (loss), net of tax:
		Foreign currency translation adjustments			—		—			—			—			766			—			—			766
		Reclassification adjustment for derivative losses reclassified into oil and gas sales			—		—			—			—			198			—			—			198
		Change in fair value of derivative financial instruments			—		—			—			—			(236	)		—			—			(236	)
		Minimum pension liability adjustment			—		—			—			—			19			—			—			19
		Unrealized gain on marketable securities			—		—			—			—			89			—			—			89
			Other comprehensive income																						836
	Comprehensive income																								2,583
Stock issued					—		15			3,816			—			—			—			2			3,833
Tax benefit related to employee stock options					—		—			31			—			—			—			—			31
Dividends on common stock					—		—			—			(39	)		—			—			—			(39	)
Dividends on preferred stock					—		—			—			(10	)		—			—			—			(10	)
Grant of restricted stock awards, net of cancellations					—		—			34			—			—			(34	)		—			—
Amortization of restricted stock awards					—		—			—			—			—			2			—			2
Other					—		1			(1	)		—			—			3			—			3
Balance as of December 31, 2003					1		47			9,043			1,614			569			(32	)		(186	)		11,056
Comprehensive income:
	Net earnings				—		—			—			2,186			—			—			—			2,186
	Other comprehensive income (loss), net of tax:
		Foreign currency translation adjustments			—		—			—			—			388			—			—			388
		Reclassification adjustment for derivative losses reclassified into oil and gas sales			—		—			—			—			410			—			—			410
		Change in fair value of derivative financial instruments			—		—			—			—			(561	)		—			—			(561	)
		Minimum pension liability adjustment			—		—			—			—			39			—			—			39
		Unrealized gain on marketable securities			—		—			—			—			85			—			—			85
			Other comprehensive income																						361
	Comprehensive income																								2,547
Stock issued					—		1			264			—			—			—			(21	)		244
Stock repurchased and retired					—		—			(189	)		—			—			—			—			(189	)
Conversion of preferred stock of a subsidiary					—		—			—			—			—			—			56			56
Tax benefit related to employee stock options					—		—			54			—			—			—			—			54
Dividends on common stock					—		—			—			(97	)		—			—			—			(97	)
Dividends on preferred stock					—		—			—			(10	)		—			—			—			(10	)
Grant of restricted stock awards, net of cancellations					—		—			66			—			—			(66	)		—			—
Amortization of restricted stock awards					—		—			—			—			—			11			—			11
Retirement of treasury stock					—		—			(151	)		—			—			—			151			—
Other					—		—			—			—			—			2			—			2
Balance as of December 31, 2004					1		48			9,087			3,693			930			(85	)		—			13,674
Comprehensive income:
	Net earnings				—		—			—			2,930			—			—			—			2,930
	Other comprehensive income (loss), net of tax:
		Foreign currency translation adjustments			—		—			—			—			162			—			—			162
		Reclassification adjustment for derivative losses reclassified into oil and gas sales			—		—			—			—			444			—			—			444
		Change in fair value of derivative financial instruments			—		—			—			—			(155	)		—			—			(155	)
		Minimum pension liability adjustment			—		—			—			—			(5	)		—			—			(5	)
		Unrealized gain on marketable securities			—		—			—			—			38			—			—			38
			Other comprehensive income																						484
	Comprehensive income																								3,414
Stock issued					—		1			125			—			—			—			—			126
Stock repurchased and retired					—		(5	)		(2,270	)		—			—			—			(2	)		(2,277	)
Tax benefit related to employee stock options					—		—			44			—			—			—			—			44
Dividends on common stock					—		—			—			(136	)		—			—			—			(136	)
Dividends on preferred stock					—		—			—			(10	)		—			—			—			(10	)
Grant of restricted stock awards, net of cancellations					—		—			80			—			—			(80	)		—			—
Amortization of restricted stock awards					—		—			—			—			—			27			—			27
Balance as of December 31, 2005				$	1		44			7,066			6,477			1,414			(138	)		(2	)		14,862

See accompanying notes to consolidated financial statements.

65

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

					Year Ended December 31,
					2005			2004			2003
					(In millions)
Cash flows from operating activities:
	Net earnings				$	2,930			2,186			1,731
	Adjustments to reconcile net earnings to net cash provided by operating activities:
		Depreciation, depletion and amortization				2,191			2,290			1,793
		Accretion of asset retirement obligation				44			44			36
		Amortization of (premiums) discounts on long-term debt, net				—			(5	)		4
		Effects of changes in foreign currency exchange rates				(2	)		(23	)		(69	)
		Non-cash change in fair value of derivative financial instruments				55			62			(1	)
		Deferred income tax expense				384			355			321
		Net (gain) loss on sale of assets				(150	)		(34	)		7
		Reduction of carrying value of oil and gas properties				212			—			111
		Other				31			31			(48	)
		Changes in assets and liabilities, net of effects of acquisitions of businesses:
			(Increase) decrease in:
				Accounts receivable		(270	)		(345	)		(164	)
				Other current assets		(16	)		(20	)		(34	)
				Long-term other assets		52			(91	)		—
			Increase (decrease) in:
				Accounts payable		262			190			42
				Income taxes payable		69			208			62
				Accrued interest and expenses		(41	)		(79	)		(2	)
				Long-term debt, including current maturities		(67	)		16			15
				Long-term other liabilities		(72	)		31			(36	)
			Net cash provided by operating activities			5,612			4,816			3,768
Cash flows from investing activities:
	Proceeds from sale of property and equipment					2,151			95			179
	Capital expenditures, including acquisitions of businesses					(4,090	)		(3,103	)		(2,587	)
	Purchases of short-term investments					(4,020	)		(3,215	)		(702	)
	Sales of short-term investments					4,307			2,589			361
	Other					—			—			(24	)
			Net cash used in investing activities			(1,652	)		(3,634	)		(2,773	)
Cash flows from financing activities:
	Proceeds from borrowings of long-term debt, net of issuance costs					—			—			597
	Principal payments on long-term debt					(1,258	)		(973	)		(1,118	)
	Issuance of common stock, net of issuance costs					124			268			155
	Repurchase of common stock					(2,263	)		(189	)		—
	Dividends paid on common stock					(136	)		(97	)		(39	)
	Dividends paid on preferred stock					(10	)		(10	)		(10	)
	Increase in long-term other liabilities					—			—			1
			Net cash used in financing activities			(3,543	)		(1,001	)		(414	)
Effect of exchange rate changes on cash						37			39			59
Net increase in cash and cash equivalents						454			220			640
Cash and cash equivalents at beginning of year						1,152			932			292
Cash and cash equivalents at end of year					$	1,606			1,152			932

See accompanying notes to consolidated financial statements.

66

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

      Accounting policies used by Devon Energy Corporation and subsidiaries (“Devon”) reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such policies are briefly discussed below.

Nature of Business and Principles of Consolidation

      Devon is engaged primarily in oil and gas exploration, development and production, and the acquisition of properties. Such activities domestically are concentrated in four geographic areas:

•  the Permian Basin within Texas and New Mexico;

•  the Rocky Mountains area of the United States stretching from the Canadian Border into Northern New Mexico;

•  the Mid-Continent area of the central and southern United States; and

•  the Gulf Coast, which includes properties located primarily in the onshore South Texas and South Louisiana areas and offshore in the Gulf of Mexico.

      Devon’s Canadian activities are located primarily in the Western Canadian Sedimentary Basin. Devon’s international activities — outside of North America — are located primarily in Azerbaijan, Brazil, China, Egypt, Russia and areas in West Africa, including Equatorial Guinea, Gabon and Cote d’Ivoire.

      Devon also has marketing and midstream operations which are responsible for marketing natural gas, crude oil and NGLs, and constructing and operating pipelines, storage and treating facilities and gas processing plants. These services are performed for Devon as well as for unrelated third parties.

      The accounts of Devon’s wholly owned subsidiaries are included in the accompanying consolidated financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in the Preparation of Financial Statements

      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include estimates of proved reserves and related present value estimates of future net revenue, the carrying value of oil and gas properties, goodwill impairment assessment, asset retirement obligations, income taxes, valuation of derivative instruments, obligations related to employee benefits and legal and environmental risks and exposures.

Property and Equipment

      Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized.

67

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred to amortizable costs over average holding periods ranging from three years for onshore properties to seven years for offshore properties.

      Net capitalized costs are limited to the estimated future net revenues, discounted at 10% per annum, from proved oil, natural gas and NGL reserves plus the cost of properties not subject to amortization. Estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties. Such limitations are imposed separately on a country-by-country basis and are tested quarterly. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

      Depreciation of midstream pipelines are provided on a units-of-production basis. Depreciation and amortization of other property and equipment, including corporate and other midstream assets and leasehold improvements, are provided using the straight-line method based on estimated useful lives from three to 39 years.

      Effective January 1, 2003, Devon adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”) using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. SFAS No. 143 requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants. The obligations included within the scope of SFAS No. 143 are those for which a company faces a legal obligation. The initial measurement of the asset retirement obligation is to record a separate liability at its fair value with an offsetting asset retirement cost recorded as an increase to the related property and equipment on the consolidated balance sheet. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

      Devon had previously estimated costs of dismantlement, removal, site reclamation, and other similar activities in the total costs that were subject to depreciation, depletion, and amortization. However, Devon did not record a separate asset or liability for such amounts. Upon adoption, Devon recorded a cumulative-effect-type adjustment for an increase to net earnings of $16 million net of deferred taxes of $10 million. Additionally, Devon established an asset retirement obligation of $453 million, an increase to property and equipment of $400 million and a decrease in accumulated DD&A of $79 million.

      In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (“SAB No. 106”) to provide guidance regarding the interaction of SFAS No. 143 with the full cost method of accounting for oil and gas properties. Specifically, SAB No. 106 clarifies the manner in which the full cost ceiling test and depletion of oil and gas properties should be calculated in accordance with the provisions of SFAS No. 143. Devon adopted SAB No. 106 prospectively in the fourth quarter of 2004. However, this adoption has not materially impacted the full cost ceiling test calculation or depletion since adoption.

68

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Short-Term Investments and Other Marketable Securities

      Devon reports its short-term investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. At December 31, 2005 and 2004, Devon’s short-term investments consisted of $680 million and $967 million, respectively, of auction rate securities classified as available for sale. Although Devon’s auction rate securities have contractual maturities of more than 10 years, the underlying interest rates on such securities reset at intervals ranging from seven to 90 days. Therefore, these auction rate securities are priced and subsequently trade as short-term investments because of the interest rate reset feature. As a result, Devon has classified its auction rate securities as short-term investments in the accompanying consolidated balance sheet.

      Devon’s only other significant investment security is its investment in approximately 14.2 million shares of Chevron Corporation (“Chevron”) common stock which is reported at fair value. Except for unrealized losses that are determined to be “other than temporary”, the tax effected unrealized gain or loss on the investment in Chevron common stock is recognized in other comprehensive income (loss) and reported as a separate component of stockholders’ equity.

Goodwill

      Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. Devon performed annual impairment tests of goodwill in the fourth quarters of 2005, 2004 and 2003. Based on these assessments, no impairment of goodwill was required.

      The table below provides a summary of Devon’s goodwill, by assigned reporting unit, as of December 31, 2005 and 2004:

		December 31,
		2005		2004
		(In millions)
United States		$	3,056		3,061
Canada			2,581		2,508
International			68		68
	Total	$	5,705		5,637

Revenue Recognition and Gas Balancing

      Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline or truck or a tanker lifting has occurred. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met.

      Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These

69

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under produced owner to recoup its entitled share through production. If an imbalance exists at the time the wells’ reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements. The liability is priced based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met.

      Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, when delivery or performance has occurred and title has transferred, and if collectibility of the revenue is probable. Revenues and expenses attributable to Devon’s gas and NGL purchase and processing contracts are reported on a gross basis since Devon takes title to the products and has risks and rewards of ownership. The gas purchased under these contracts is processed in Devon-owned plants.

Major Purchasers

      No purchaser accounted for over 10% of revenues in 2005, 2004 and 2003.

Derivative Instruments

      Historically, Devon has entered into oil and gas financial instruments to manage its exposure to oil and gas price volatility. Devon has also entered into interest rate swaps to manage its exposure to interest rate volatility. The interest rate swaps mitigate either the effects of interest rate fluctuations on interest expense for variable-rate debt instruments, or the debt fair values for fixed-rate debt. At December 31, 2005, the only derivative financial instruments outstanding consisted of interest rate swaps.

      All derivatives are recognized as fair value of financial instruments on the consolidated balance sheets at their fair value. Prior to December 31, 2005, a substantial portion of Devon’s derivatives consisted of contracts that hedged the price of future oil and natural gas production. At inception, these derivative contracts were cash flow hedges that qualified for hedge accounting treatment. Therefore, while fair values of such hedging instruments must be estimated as of the end of each reporting period, the changes in the fair values attributable to the effective portion of these hedging instruments are not included in Devon’s consolidated results of operations. Instead, the changes in fair value of the effective portion of these hedging instruments, net of tax, are recorded directly to accumulated other comprehensive income, a component of stockholders’ equity, until the hedged oil or natural gas quantities are produced. The ineffective portion of these hedging instruments is included in consolidated results of operations as change in fair value of derivative financial instruments.

      To qualify for hedge accounting treatment, Devon designates its cash flow hedge instruments as such on the date the derivative contract is entered into or the date of a business combination which includes cash flow hedge instruments. Additionally, Devon documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. Devon also assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. If Devon fails to meet the requirements for using hedge accounting, changes in fair value of these hedging instruments would not be recorded directly to equity but in the consolidated results of operations. During 2004 and 2003, no derivatives ceased to qualify for hedge accounting.

      In the third quarter of 2005, certain oil derivatives ceased to qualify for hedge accounting primarily as a result of deferred production caused by hurricanes in the Gulf of Mexico. Because these contracts no longer qualified for hedge accounting, Devon recognized $39 million in losses as change in fair value of derivative financial instruments in the accompanying statement of operations.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      In the first half of 2005, Devon recognized a $55 million loss related to certain oil hedges that no longer qualified for hedge accounting due to the property divestiture program. These commodity instruments related to 5,000 barrels per day of U.S. oil production and 3,000 barrels per day of Canadian oil production from properties that were sold as part of Devon’s divestiture program. This loss is presented in other income in the statement on operations.

      By using derivative instruments to hedge exposures to changes in commodity prices and interest rates, Devon exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with counterparties that Devon believes are minimal credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers.

      Market risk is the change in the value of a derivative instrument that results from a change in commodity prices or interest rates. The market risk associated with commodity price and interest rate contracts is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The oil and gas reference prices upon which the commodity hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon. Devon does not hold or issue derivative instruments for speculative trading purposes.

      During 2005, 2004 and 2003, Devon recorded in its statements of operations losses of $94 million and $62 million and a gain of $1 million, respectively, for the change in the fair value of derivative instruments that do not qualify for hedge accounting treatment, as well as the ineffectiveness of derivatives that do qualify as hedges.

Common Stock

      On September 27, 2004, Devon declared a two-for-one stock split, effected in the form of a stock dividend, to stockholders of record on October 29, 2004. Common stock shares and per share amounts prior to 2004 have been restated to reflect this two-for-one stock split.

Stock Options

      Devon applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, in accounting for its fixed plan stock options. As such, compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, Accounting for Stock-Based Compensation, (“SFAS No. 123”) established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS No. 123, Devon has elected to continue to apply the intrinsic value-based method of accounting described above, and has adopted the disclosure requirements of SFAS No. 123.

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Had Devon elected the fair value provisions of SFAS No. 123 and recognized compensation expense over the vesting period based on the fair value of the stock options granted as of their grant date, Devon’s 2005, 2004 and 2003 pro forma net earnings and pro forma net earnings per share would have differed from the amounts actually reported as shown in the following table.

			Year Ended December 31,
			2005			2004			2003
			(In millions, except per
			share amounts)
Net earnings available to common stockholders, as reported			$	2,920			2,176			1,737
Add stock-based employee compensation expense included in reported net earnings, net of related tax expense				18			7			2
Deduct total stock-based employee compensation expense determined under fair value based method for all awards (see note 9), net of related tax expense				(44	)		(31	)		(23	)
Net earnings available to common stockholders, pro forma			$	2,894			2,152			1,716
Net earnings per share available to common stockholders:
	As reported:
		Basic	$	6.38			4.51			4.16
		Diluted	$	6.26			4.38			4.04
	Pro forma:
		Basic	$	6.32			4.46			4.11
		Diluted	$	6.21			4.33			3.99

      The weighted average fair values of stock options granted during 2005, 2004 and 2003 were $19.65, $10.32 and $8.14, respectively. The fair value of each option grant was estimated for disclosure purposes on the date of grant using the Black-Scholes Option Pricing Model with the following assumptions for 2005, 2004 and 2003, respectively: risk-free interest rates of 4.4%, 3.2% and 2.8%; dividend yields of 0.6%, 0.5% and 0.4%; expected lives of four, four and four years; and volatility of the price of the underlying common stock of 31.0%, 32.2% and 37.9%.

Income Taxes

      Devon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. At December 31, 2005, undistributed earnings of foreign subsidiaries were determined to be permanently reinvested. Therefore, no U.S. deferred income taxes were provided on such amounts at December 31, 2005.

      In October 2004, Congress enacted new tax legislation allowing qualifying corporations to repatriate cash from foreign operations at a reduced income tax rate. In 2005, Devon repatriated $545 million, substantially all of which was from Canadian operations and was taxed at the reduced income tax rate. As a result, Devon recognized approximately $28 million of additional current income tax expense. In addition, this tax legislation creates a new U.S. tax deduction which will be phased in starting in 2005 for companies with domestic production activities, including oil and gas extraction.

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