DEVON ENERGY CORP/DE (Form: 10-K, Received: 03/03/2006 15:08:43)

/s/ Michael M. Kanovsky

Michael M. Kanovsky

March 1, 2006

/s/ J. Todd Mitchell

J. Todd Mitchell

March 1, 2006

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

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

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.

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

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

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.

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.

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

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

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.

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.

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

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,

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

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

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.

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.


(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

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


(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

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.


	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.

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

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

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.

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.


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


			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.


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

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.

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


		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


		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.

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.


	*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.


	*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

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.


	*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

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

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

$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”.


	*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

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

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.


	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

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

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 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

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

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

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

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

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%


	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

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.


	*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

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

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, CO ₂ 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.


	*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.


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.

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

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*General and Administrative Expenses*

General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.


	*Net Earnings Per Common Share*

Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if Devon’s dilutive outstanding stock options were exercised (calculated using the treasury stock method), if the previously outstanding preferred stock of a subsidiary were converted to common stock and if Devon’s previously outstanding zero coupon convertible senior debentures were converted to common stock.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for 2005, 2004 and 2003.


		Net
		Earnings		Weighted
		Applicable to		Average		Net
		Common		Common Shares		Earnings
		Stockholders		Outstanding		per Share

		(In millions, except per share amounts)
Year Ended December 31, 2005:
	Basic earnings per share	$	2,920		458	$	6.38
	Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—		8
	Dilutive effect of potential common shares issuable upon conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $14 million)(1)		24		4

	Diluted earnings per share	$	2,944		470	$	6.26

Year Ended December 31, 2004:
	Basic earnings per share	$	2,176		482	$	4.51
	Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—		8
	Dilutive effect of potential common shares issuable upon conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $6 million)		10		9

	Diluted earnings per share	$	2,186		499	$	4.38

Year Ended December 31, 2003:
	Basic earnings per share	$	1,737		417	$	4.16
	Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—		6
	Dilutive effect of potential common shares issuable upon conversion of preferred stock of subsidiary acquired in 2003 merger		2		1
	Dilutive effect of potential common shares issuable upon conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $6 million)		9		9

	Diluted earnings per share	$	1,748		433	$	4.04


(1)	The senior convertible debentures were retired in June 2005 prior to their stated maturity.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Certain options to purchase shares of Devon’s common stock have been excluded from the dilution calculations because the options’ exercise price exceeded the average market price of Devon’s common stock during the applicable year. The following information relates to these options.


	2005			2004		2003

Options excluded from dilution calculation (in millions)		— (1	)		4		10
Range of exercise prices	$	56.09 - $68.64		$	33.00 - $44.83	$	24.96 - $44.83
Weighted average exercise price	$	66.01		$	38.22	$	28.05


(1)	Actual amount of options excluded from the 2005 dilution calculation are 154,000 shares.

The excluded options for 2005 expire between July 28, 2010 and December 11, 2013.


	*Foreign Currency Translation Adjustments*

Devon’s Canadian subsidiaries use the Canadian dollar as their functional currency. Therefore, the assets and liabilities of Devon’s Canadian subsidiaries are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates, while income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. Devon’s International subsidiaries use the U.S. dollar as their functional currency.


	*Statements of Cash Flows*

For purposes of the consolidated statements of cash flows, Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.


	*Commitments and Contingencies*

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Environmental expenditures are expensed or capitalized in accordance with accounting principles generally accepted in the United States of America. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Reference is made to note 12 for a discussion of amounts recorded for these liabilities.


	*Reclassifications*

Certain prior period amounts have been reclassified to conform to the current year presentation.


	*Recently Issued Accounting Standards Not Yet Adopted*

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

expensed over the applicable vesting period. Also, pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. Devon will adopt the provisions of SFAS No. 123(R) in the first quarter of 2006 using the modified prospective method. Under this method, Devon 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 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.


2.	Business Combinations and Pro Forma Information


	*Ocean Energy, Inc.*

On April 25, 2003, Devon completed its merger with Ocean Energy, Inc. (“Ocean”). In the transaction, Devon issued 0.828 shares of its common stock for each outstanding share of Ocean common stock (or a total of approximately 148 million shares). Also, Devon assumed approximately $1.8 billion of debt (current and long-term) from Ocean.

Devon acquired Ocean primarily for the significant production, development projects and exploration prospects in both the deepwater Gulf of Mexico and internationally, and the additional producing assets onshore in the United States and in the shallower shelf regions of the Gulf of Mexico.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The calculation of the purchase price and the allocation to assets and liabilities are shown below.


			(In millions,
			except share price)
Calculation and allocation of purchase price:
	Shares of Devon common stock issued to Ocean stockholders			148
	Average Devon stock price		$	24.03

	Fair value of common stock issued		$	3,546
	Plus merger costs incurred			114
	Plus fair value of Ocean convertible preferred stock assumed by a Devon subsidiary			64
	Plus fair value of Ocean employee stock options assumed by Devon			124

		Total purchase price		3,848
Plus fair value of liabilities assumed by Devon:
	Current liabilities			650
	Long-term debt			1,436
	Deferred revenue			97
	Asset retirement obligation, long-term			121
	Other noncurrent liabilities			89
	Deferred income taxes			954

		Total purchase price plus liabilities assumed	$	7,195

Fair value of assets acquired by Devon:
	Current assets		$	256
	Proved oil and gas properties			4,262
	Unproved oil and gas properties			1,060
	Other property and equipment			85
	Other noncurrent assets			39
	Goodwill (none deductible for income taxes)			1,493

		Total fair value of assets acquired	$	7,195

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Pro Forma Information*

Set forth in the following table is certain unaudited pro forma financial information for the year ended December 31, 2003. The information has been prepared assuming the Ocean merger was consummated on January 1, 2003. All pro forma information is based on estimates and assumptions deemed appropriate by Devon. The pro forma information is presented for illustrative purposes only. If the transactions had occurred in the past, Devon’s operating results might have been different from those presented in the following table. The pro forma information should not be relied upon as an indication of the operating results that Devon would have achieved if the transactions had occurred on January 1, 2003. The pro forma information also should not be used as an indication of future results.


				Pro Forma
				Information
				Year Ended
				December 31,
				2003

				(In millions,
				except per share
				amounts and
				production
				volumes)
				(Unaudited)
Revenues:
	Oil sales			$	1,840
	Gas sales				4,155
	NGL sales				416
	Marketing and midstream revenues				1,461

		Total revenues			7,872

Expenses and other income, net:
	Lease operating expenses				1,167
	Production taxes				219
	Marketing and midstream operating costs and expenses				1,174
	Depreciation, depletion and amortization of oil and gas properties				1,859
	Depreciation and amortization of non-oil and gas properties				125
	Accretion of asset retirement obligation				38
	General and administrative expenses				340
	Interest expense				515
	Effects of changes in foreign currency exchange rates				(69	)
	Change in fair value of derivative financial instruments				(1	)
	Reduction of carrying value of oil and gas properties				111
	Other income, net				(37	)

			Total expenses and other income, net		5,441

Earnings before income taxes and cumulative effect of change in accounting principle					2,431
Income tax expense:
	Current				219
	Deferred				372

			Total income tax expense		591

Earnings before cumulative effect of change in accounting principle					1,840
Cumulative effect of change in accounting principle, net of tax					29

Net earnings					1,869
Preferred stock dividends					10

Net earnings applicable to common stockholders				$	1,859

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		Pro Forma
		Information
		Year Ended
		December 31,
		2003

		(In millions,
		except per share
		amounts and
		production
		volumes)
		(Unaudited)
Basic earnings per average common share outstanding:
	Earnings before cumulative effect of change in accounting principle	$	3.95
	Cumulative effect of change in accounting principle, net of tax		0.06

	Net earnings	$	4.01

Diluted earnings per average common share outstanding:
	Earnings before cumulative effect of change in accounting principle	$	3.83
	Cumulative effect of change in accounting principle, net of tax		0.06

	Net earnings	$	3.89

Weighted average common shares outstanding — basic			463
Weighted average common shares outstanding — diluted			481
Production volumes:
	Oil (MMBbls)		72
	Gas (Bcf)		913
	NGLs (MMBbls)		23
	MMBoe		247


3.	Comprehensive Income or Loss

Devon’s comprehensive income or loss information is included in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss). A summary of accumulated other

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

comprehensive income or loss as of December 31, 2005, 2004 and 2003, and changes during each of the years then ended, is presented in the following table.


		Foreign			Change in			Minimum			Unrealized
		Currency			Fair Value of			Pension			Gain on
		Translation			Derivative			Liability			Marketable
		Adjustments			Instruments			Adjustments			Securities			Total

		(In millions)
Balance as of December 31, 2002		$	(99	)		(97	)		(71	)		—			(267	)
	2003 activity		894			(41	)		28			141			1,022
	Deferred taxes		(128	)		3			(9	)		(52	)		(186	)

	2003 activity, net of deferred taxes		766			(38	)		19			89			836

Balance as of December 31, 2003			667			(135	)		(52	)		89			569
	2004 activity		426			(213	)		61			132			406
	Deferred taxes		(38	)		62			(22	)		(47	)		(45	)

	2004 activity, net of deferred taxes		388			(151	)		39			85			361

Balance as of December 31, 2004			1,055			(286	)		(13	)		174			930
	2005 activity		181			430			(8	)		60			663
	Deferred taxes		(19	)		(141	)		3			(22	)		(179	)

	2005 activity, net of deferred taxes		162			289			(5	)		38			484

Balance as of December 31, 2005		$	1,217			3			(18	)		212			1,414


4.	Supplemental Cash Flow Information

Cash payments for interest and income taxes in 2005, 2004 and 2003 are presented below:


	Year Ended
	December 31,

	2005		2004		2003

	(In millions)
Interest paid	$	663		474		508
Income taxes paid	$	1,092		477		123

The 2003 Ocean merger involved non-cash consideration as presented below:


	Ocean
	Merger

	(In millions)
Value of common stock issued	$	3,546
Convertible preferred stock assumed		64
Employee stock options assumed		124
Liabilities assumed		2,393
Deferred tax liability created		954

Fair value of assets acquired with non-cash consideration	$	7,081

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


5.	Accounts Receivable

The components of accounts receivable include the following:


		December 31,

		2005			2004

		(In millions)
Oil, gas and NGL revenue		$	1,149			946
Joint interest billings			206			159
Marketing and midstream revenue			173			162
Other			78			60

			1,606			1,327
Allowance for doubtful accounts			(5	)		(7	)

	Net accounts receivable	$	1,601			1,320


6.	Property and Equipment and Asset Retirement Obligations

Property and equipment included the following:


			December 31,

			2005			2004

			(In millions)
Oil and gas properties:
	Subject to amortization		$	29,631			27,257
	Not subject to amortization			2,747			3,187
	Accumulated depreciation, depletion and amortization			(14,598	)		(12,410	)

		Net oil and gas properties		17,780			18,034

Other property and equipment				1,868			1,670
Accumulated depreciation and amortization				(516	)		(358	)

		Net other property and equipment		1,352			1,312

Property and equipment, net of accumulated depreciation, depletion and amortization			$	19,132			19,346

The costs not subject to amortization relate to unproved properties which are excluded from amortized capital costs until it is determined whether or not proved reserves can be assigned to such properties. The excluded properties are assessed for impairment quarterly. Subject to industry conditions, evaluation of most of these properties, and the inclusion of their costs in the amortized capital costs is expected to be completed within five years.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2005:


		Costs Incurred In

								Prior to
		2005		2004		2003		2003		Total

		(In millions)
Acquisition costs		$	334		134		467		950		1,885
Exploration costs			330		172		120		30		652
Development costs			19		—		44		—		63
Capitalized interest			60		54		32		1		147

	Total oil and gas properties costs not subject to amortization	$	743		360		663		981		2,747

At December 31, 2005, Devon’s investment in countries where proved reserves have not been established was $232 million. This amount included $116 million in Nigeria, $113 million in Brazil and $3 million in Ghana.

In September 2004, Devon announced its plans to divest certain non-core oil and gas properties in the offshore Gulf of Mexico and onshore in the United States and Canada. During 2005, Devon closed all such property divestitures and received $2.0 billion of gross proceeds, net of all purchase price adjustments. After-tax, the proceeds are approximately $1.8 billion. Certain information regarding these sales is included in the following table.


	United States		Canada		Total

	($ in millions)
Gross proceeds	$	966		1,029		1,995
After-tax proceeds	$	786		1,027		1,813
Asset retirement obligations assumed by purchasers	$	160		39		199
Reserves sold (MMBoe)		89		87		176

Under full cost accounting rules, a gain or loss on the sale or other disposition of oil and gas properties is not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Because the divestitures that closed in 2005 did not significantly alter such relationship, Devon did not recognize a gain or loss on these divestitures. Therefore, the proceeds from these transactions were recognized as an adjustment of capitalized costs in the respective cost centers.

As described in Note 1, effective January 1, 2003, Devon adopted SFAS No. 143 and began recording asset retirement obligations for estimated property and equipment dismantlement, abandonment and restoration costs when a legal obligation is incurred. In accordance with SFAS No. 143, oil and gas properties subject to amortization and other property and equipment listed above include asset retirement

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

costs associated with these asset retirement obligations. Following is a reconciliation of the asset retirement obligation for the years ended December 31, 2005 and 2004.


		Year Ended
		December 31,

		2005			2004

		(In millions)
Asset retirement obligation as of beginning of year		$	739			671
	Liabilities incurred		119			51
	Liabilities settled		(42	)		(42	)
	Liabilities assumed by others		(199	)		(4	)
	Accretion expense on discounted obligation		44			44
	Foreign currency translation adjustment		7			19

Asset retirement obligation as of end of year			668			739
Less current portion			50			46

Asset retirement obligation, long-term		$	618			693

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


7.	Long-Term Debt and Related Expenses

A summary of Devon’s long-term debt is as follows:


		December 31,

		2005			2004

		(In millions)
Debentures exchangeable into shares of Chevron Corporation common stock:
	4.90% due August 15, 2008	$	444			444
	4.95% due August 15, 2008		316			316
	Discount on exchangeable debentures		(51	)		(68	)
Zero coupon convertible senior debentures exchangeable into shares of Devon common stock, due June 27, 2020 (retired in 2005)			—			419
Other debentures and notes:
	7.625% due July 1, 2005		—			125
	7.25% due July 18, 2005 ($175 million Canadian)		—			145
	10.25% due November 1, 2005		—			236
	2.75% due August 1, 2006		500			500
	6.55% due August 2, 2006 ($200 million Canadian)		172			166
	4.375% due October 1, 2007		400			400
	10.125% due November 15, 2009		177			177
	6.75% due March 15, 2011 (retired in 2005)		—			400
	6.875% due September 30, 2011		1,750			1,750
	7.25% due October 1, 2011		350			350
	8.25% due July 1, 2018		125			125
	7.50% due September 15, 2027		150			150
	7.875% due September 30, 2031		1,250			1,250
	7.95% due April 15, 2032		1,000			1,000
	Other		3			3
	Fair value adjustment on debt related to interest rate swaps		(18	)		9
	Net premium on other debentures and notes		51			67

			6,619			7,964
Less amount classified as current			662			933

Long-term debt		$	5,957			7,031

Maturities of long-term debt as of December 31, 2005, excluding the $18 million fair value adjustment, are as follows (in millions):


2006		$	673
2007			400
2008			762
2009			177
2010			—
2011 and thereafter			4,625

	Total	$	6,637

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Credit Facilities with Banks*

Devon has a $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.

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, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. Devon is 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 on April 7, 2006, provided Devon has not experienced a “material adverse effect,” as defined in the Senior Credit Facility agreement, at that date.

Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears.

The agreement governing the Senior Credit Facility contains certain covenants and restrictions, including a maximum allowed debt-to -capitalization ratio of 65% as defined in the agreement. At December 31, 2005, Devon was in compliance with such covenants and restrictions. Devon’s debt-to-capitalization ratio at December 31, 2005, as calculated pursuant to the terms of the agreement, was 27.0%.

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.


	*Commercial Paper*

Devon also has a commercial paper program under which it may borrow up to $725 million. Borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. The commercial paper borrowings may have terms of up to 365 days and bear interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, London Interbank Offered Rate (LIBOR), or the money market rate as found on the commercial paper market. As of December 31, 2005 and 2004, Devon had no commercial paper debt outstanding.


	*Exchangeable Debentures*

The exchangeable debentures consist of $444 million of 4.90% debentures and $316 million of 4.95% debentures. The exchangeable debentures were issued on August 3, 1998 and mature August 15, 2008. The exchangeable debentures were callable beginning August 15, 2000, initially at 104.0% of principal and at prices declining to 100.5% of principal on or after August 15, 2007. At December 31, 2005, the call price was 101.5% of principal. The exchangeable debentures are exchangeable at the option of the holders at any time prior to maturity, unless previously redeemed, for shares of Chevron common stock. In lieu of delivering Chevron common stock to an exchanging debenture holder, Devon may, at its option, pay to such holder an amount of cash equal to the market value of the Chevron common stock. At maturity, holders who have not exercised their exchange rights will receive an amount in cash equal to the principal amount of the debentures.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2005, Devon beneficially owned approximately 14.2 million shares of Chevron common stock. These shares have been deposited with an exchange agent for possible exchange for the exchangeable debentures. Each $1,000 principal amount of the exchangeable debentures is exchangeable into 18.6566 shares of Chevron common stock, an exchange rate equivalent to $53.60 per share of Chevron stock.

The exchangeable debentures were assumed as part of the PennzEnergy merger. The fair values of the exchangeable debentures were determined as of August 17, 1999, based on market quotations. In accordance with derivative accounting standards, the total fair value of the debentures has been allocated between the interest-bearing debt and the option to exchange Chevron common stock that is embedded in the debentures. Accordingly, a discount was recorded on the debentures and is being accreted using the effective interest method which raised the effective interest rate on the debentures to 7.76%.


	*Zero Coupon Convertible Debentures*

In June 2005, Devon redeemed the zero coupon convertible debentures prior to their scheduled maturity of June 27, 2020. Devon’s obligation to settle the conversions and redeem the debentures totaled $452 million and was satisfied with cash on hand. The total cash payments to settle the conversions and redeem the debentures exceeded the accreted value of the debentures by $25 million. This $25 million, as well as $5 million of unamortized issuance costs, are included in interest expense in the accompanying 2005 statements of operations. The after-tax effect of these expenses was $19 million.


	*Other Debentures and Notes*

Following are descriptions of the various other debentures and notes outstanding at December 31, 2005, as listed in the table presented at the beginning of this note.


	Ocean Debt

In connection with the Ocean merger, Devon assumed $1.8 billion of debt. The table below summarizes the debt assumed which remains outstanding, the fair value of the debt at April 25, 2003, and the effective interest rate of the debt assumed after determining the fair values of the respective notes using April 25, 2003, market interest rates. The premiums are being amortized using the effective interest method. All of the notes are general unsecured obligations of Devon.


	Fair Value
	of Debt		Effective Rate of
Debt Assumed	Assumed		Debt Assumed

	(In millions)
4.375% due October 2007 (principal of $400 million)	$	410		3.8	%
7.250% due October 2011 (principal of $350 million)	$	406		4.9	%
8.250% due July 2018 (principal of $125 million)	$	147		5.5	%
7.500% due September 2027 (principal of $150 million)	$	169		6.5	%

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Anderson Debt

In connection with the Anderson acquisition, Devon assumed $702 million of senior notes. The table below summarizes the debt assumed which remains outstanding, the fair value of the debt at October 15, 2001, and the effective interest rate of the debt assumed after determining the fair values of the respective notes using October 15, 2001, market interest rates. The premium is being amortized using the effective interest method. The senior notes are general unsecured obligations of Devon.


	Fair Value
	of Debt		Effective Rate of
Debt Assumed	Assumed		Debt Assumed

	(In millions)
6.55% senior notes due 2006 (principal of $200 million Canadian)	$	129		6.5%


	2.75% Notes due August 1, 2006

On August 4, 2003, Devon issued these notes which are unsecured and unsubordinated obligations of Devon. The proceeds from the issuance of these debt securities, net of discounts and issuance costs, of $498 million were used to repay amounts outstanding under Devon’s $3 billion term loan credit facility.


	10.125% Debentures due November 15, 2009

These debentures were assumed as part of the PennzEnergy acquisition. The fair value of the debentures was determined using August 17, 1999, market interest rates. As a result, premiums were recorded on these debentures which lowered their effective interest rate to 8.9%. The premium is being amortized using the effective interest method.


	6.875% Notes due September 30, 2011 and 7.875% Debentures due September 30, 2031

On October 3, 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), sold these notes and debentures which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed on an unsecured and unsubordinated basis the obligations of Devon Financing under the debt securities. The proceeds from the issuance of these debt securities were used to fund a portion of the Anderson acquisition. The $3 billion of debt securities were structured in a manner that results in an expected weighted average after-tax borrowing rate of approximately 1.65%.


	7.95% Notes due April 15, 2032

On March 25, 2002, Devon sold these notes which are unsecured and unsubordinated obligations of Devon. The net proceeds received, after discounts and issuance costs, were $986 million and were partially used to pay down $820 million on Devon’s $3 billion term loan credit facility. The remaining $166 million of net proceeds was used in June 2002 to partially fund the early extinguishment of $175 million of 8.75% senior subordinated notes due June 15, 2007.


	$400 million 6.75% Senior Notes due March 15, 2011

On September 12, 2005, Devon redeemed the $400 million 6.75% notes due 2011, using cash on hand. Devon incurred a $51 million premium in conjunction with the early retirement. The $51 million premium is included in interest expense in the accompanying 2005 statement of operations. The after-tax effect of the $51 million premium was $34 million.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Interest Expense*

Following are the components of interest expense for the years 2005, 2004 and 2003:


	December 31, Year Ended

	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


	*Effects of Changes in Foreign Currency Exchange Rates*

Devon had $400 million of 6.75% fixed-rate senior notes payable by one of its Canadian subsidiaries. However, the notes were denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar from the dates the notes were assumed as part of an acquisition to the date of repayment increased or decreased the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent of the debt and certain cash and other working capital amounts of Devon’s Canadian subsidiary which are also denominated in U.S. dollars are required to be included in determining net earnings for the period in which the exchange rate changed. Devon redeemed these notes on September 12, 2005, and, as a result of changes in the rate of conversion of Canadian dollars to U.S. dollars, $9 million, $22 million, and $69 million was recorded as a reduction of expense in 2005, 2004 and 2003, respectively.


8.	Income Taxes

At December 31, 2005, Devon had the following net operating loss carryforwards which are available to reduce future taxable income in the jurisdiction where the net operating loss was incurred. These carryforwards will result in a future tax reduction based upon the future tax rate applicable to the taxable income that is ultimately offset by the net operating loss carryforward.


	Years of		Carryforward
Jurisdiction	Expiration		Amounts

	(In millions)
U.S. federal		2022	$	50
Various U.S. states		2006 - 2022	$	71
Canada		2008 - 2015	$	356
Azerbaijan		Indefinite	$	87

Additionally, at December 31, 2005, Devon had $18 million of U.S. minimum tax credit carryforwards which have no expiration and are available to reduce future income taxes. The net operating loss and minimum tax credit carryforward amounts have been recognized for financial purposes to reduce the net deferred tax liability at December 31, 2005.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The earnings before income taxes and the components of income tax expense (benefit) for the years 2005, 2004 and 2003 were as follows:


		Year Ended December 31,

		2005			2004			2003

		(In millions)
Earnings before income taxes:
	U.S.	$	3,254			2,264			1,603
	Canada		899			598			603
	International		399			431			39

	Total	$	4,552			3,293			2,245

Current income tax expense (benefit):
	U.S. federal	$	864			473			125
	Various states		26			10			6
	Canada		106			49			(9	)
	International		242			220			71

	Total current tax expense		1,238			752			193

Deferred income tax expense (benefit):
	U.S. federal		213			219			360
	Various states		(18	)		21			17
	Canada		217			149			(16	)
	International		(28	)		(34	)		(40	)

	Total deferred tax expense		384			355			321

Total income tax expense		$	1,622			1,107			514

Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes and cumulative effect of change in accounting principle as a result of the following:


	Year Ended December 31,

	2005			2004			2003

	(In millions)
Expected income tax expense based on U.S. statutory tax rate of 35%	$	1,593			1,153			786
Dividends received deduction		(6	)		(5	)		(5	)
Repatriation of Canadian earnings		28			—			—
United States manufacturing deduction		(25	)		—			—
State income taxes		6			20			15
Taxation on foreign operations		30			(30	)		(78	)
Effect of Canadian tax rate reductions		(14	)		(36	)		(218	)
Other		10			5			14

Total income tax expense	$	1,622			1,107			514

During 2005, Devon repatriated $545 million, substantially all of which was Canadian earnings from its Canadian subsidiary, to the U.S. which resulted in a $28 million tax effect.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In October 2004, Congress enacted new tax legislation that 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. This deduction provided a $25 million tax benefit in 2005.

During 2005, 2004 and 2003, total income tax expense was reduced by the effects of Canadian statutory rate reductions. As presented in the table above, these rate reductions resulted in $14 million, $36 million and $218 million benefits in 2005, 2004 and 2003, respectively, related to the lower tax rates being applied to deferred tax liabilities outstanding as of the beginning of the year.

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2005 and 2004 are presented below:


			December 31,

			2005			2004

			(In millions)
Deferred tax assets:
	Net operating loss carryforwards		$	148			336
	Minimum tax credit carryforwards			18			29
	Fair value of derivative financial instruments			52			157
	Asset retirement obligations			271			252
	Pension benefit obligation			49			52
	Other			102			130

	Total deferred tax assets			640			956

Deferred tax liabilities:
	Property and equipment, principally due to nontaxable business combinations, differences in depreciation, and the expensing of intangible drilling costs for tax purposes			(5,437	)		(5,366	)
	Chevron Corporation common stock			(247	)		(231	)
	Long-term debt			(168	)		(149	)
	Other			(35	)		(10	)

	Total deferred tax liabilities			(5,887	)		(5,756	)

		Net deferred tax liability	$	(5,247	)		(4,800	)

As shown in the above table, Devon has recognized $640 million of deferred tax assets as of December 31, 2005. Such amount includes $148 million from various carryforwards available to offset future income taxes. The carryforwards include federal net operating loss carryforwards which do not expire until 2022, state net operating loss carryforwards which expire primarily between 2006 and 2022, Canadian net operating loss carryforwards which expire primarily between 2008 and 2015, and Azerbaijani net operating loss carryforwards and U.S. minimum tax credit carryforwards which have no expiration. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be “more likely than not.” When the future utilization of some portion of the carryforwards is determined not to be “more likely than not,” a valuation allowance is provided to reduce the recorded tax benefits from such assets.

Devon expects the tax benefits from the net operating loss carryforwards to be utilized between 2006 and 2009. Such expectation is based upon current estimates of taxable income during this period, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon’s future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expiration.


9.	Stockholders’ Equity

The authorized capital stock of Devon consists of 800 million shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.

Effective August 17, 1999, Devon issued 1.5 million shares of 6.49% cumulative preferred stock, Series A, to holders of PennzEnergy 6.49% cumulative preferred stock, Series A. Dividends on the preferred stock are cumulative from the date of original issue and are payable quarterly, in cash, when declared by the Board of Directors. The preferred stock is redeemable at the option of Devon at any time on or after June 2, 2008, in whole or in part, at a redemption price of $100 per share, plus accrued and unpaid dividends to the redemption date.

Devon’s Board of Directors has designated a certain number of shares of the preferred stock as Series A Junior Participating Preferred Stock (the “Series A Junior Preferred Stock”) in connection with the adoption of the shareholder rights plan described later in this note. On April 25, 2003, the Board increased the designated shares from 2.0 million to 2.9 million. At December 31, 2005, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 200 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 200 votes per share (subject to adjustment to prevent dilution) on all matters submitted to a vote of the stockholders. The Series A Junior Preferred Stock is neither redeemable nor convertible. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.

The following is a summary of the changes in Devon’s common shares outstanding for 2005, 2004 and 2003:


	2005			2004			2003

	(In millions)
Shares outstanding, beginning of year		484			472			314
Exercise of stock options		5			13			10
Shares repurchased and retired		(47	)		(5	)		—
Grant of restricted stock		1			2			1
Conversion of subsidiary’s preferred stock		—			2			—
Issuance of common stock		—			—			147

Shares outstanding, end of year		443			484			472

On September 27, 2004, Devon announced a stock repurchase program to repurchase up to 50 million shares of its common stock. During 2004, Devon repurchased 5 million shares at a total cost of $189 million, or $37.78 per share. This program was completed in 2005, during which Devon repurchased 44.6 million shares at a total cost of $2.1 billion, or $47.69 per share. The total cost of this program was $2.3 billion, or $46.69 per share.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On August 3, 2005, Devon announced another program to repurchase up to 50 million shares of its common stock. This second stock repurchase program is planned to extend through 2007. Shares may be purchased from time to time depending upon market conditions. Devon plans to repurchase shares in the open market and in privately negotiated transactions. This stock repurchase program may be discontinued at any time. During 2005, Devon repurchased 2.2 million shares at a cost of $134 million, or $60.16 per share, under this program.

At December 31, 2003, a subsidiary of Devon created in the Ocean merger had 38,000 shares of convertible preferred stock outstanding. In January 2004, these shares of convertible preferred stock were canceled and converted to 2,197,160 shares of Devon common stock pursuant to an automatic conversion feature of the preferred stock. The automatic conversion feature was triggered when the closing price of Devon common stock equaled or exceeded the forced conversion price of $26.20 for 20 consecutive trading days.


	*Equity Compensation Plans*

On June 8, 2005, Devon’s stockholders adopted the 2005 Long-Term Incentive Plan which expires on June 8, 2013. This plan authorizes the compensation committee, which consists of non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards, restricted stock units, performance units and performance bonuses to selected employees. The plan also authorizes the grant of nonqualified stock options and restricted stock awards to directors. A total of 32 million shares of Devon common stock have been reserved for issuance pursuant to the plan. To calculate shares issued under the plan, options granted represent one share and other awards represent 2.2 shares.

The exercise price of stock options granted under the plans may not be less than the estimated fair market value of the stock at the date of grant. Options granted under the plans are exercisable during a period established for each grant, which period may not exceed eight years from the date of grant. In addition, the grantee must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Restricted stock awards granted under the plans are subject to pro rata vesting over at least a three-year period. During this vesting period, the fair value of the restricted stock awards granted is recognized pro rata as general and administrative expenses.

Devon also has stock option plans that were adopted in 2003, 1997 and 1993 under which stock options and restricted stock awards were issued to key management and professional employees. Options granted under these plans remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under these plans. Devon also has stock options outstanding that were assumed as part of the acquisitions of Ocean, Mitchell Energy & Development Corp., Santa Fe Snyder and PennzEnergy.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of stock options related to each of these equity compensation plans as of December 31, 2005 is presented below:


		Options
Plan		Outstanding

		(In thousands)
2005 Plan			2,640
2003 Plan			5,244
1997 Plan			5,937
1993 Plan			88
Ocean Energy			1,559
Mitchell Energy			240
Santa Fe Snyder			69
PennzEnergy			955

	Totals		16,732

A summary of the status of Devon’s stock option plans as of December 31, 2003, 2004 and 2005, and changes during each of the years then ended, is presented below.


		Options Outstanding					Options Exercisable

					Weighted				Weighted
					Average				Average
		Number			Exercise		Number		Exercise
		Outstanding			Price		Exercisable		Price

		(In thousands)					(In thousands)
Balance at December 31, 2002			22,461		$	20.50		13,983	$	20.03

	Options granted		3,008		$	26.38
	Options assumed in the Ocean merger		15,852		$	19.84
	Options exercised		(9,732	)	$	16.75
	Options forfeited		(899	)	$	26.10

Balance at December 31, 2003			30,690		$	21.76		22,920	$	21.30

	Options granted		3,176		$	37.76
	Options exercised		(13,479	)	$	19.84
	Options forfeited		(612	)	$	24.96

Balance at December 31, 2004			19,775		$	25.54		13,027	$	23.27

	Options granted		2,705		$	65.63
	Options exercised		(5,446	)	$	23.02
	Options forfeited		(302	)	$	31.34

Balance at December 31, 2005			16,732		$	32.74		10,915	$	25.04

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes information about Devon’s stock options which were outstanding, and those which were exercisable, as of December 31, 2005.


	Options Outstanding						Options Exercisable

			Weighted		Weighted				Weighted
			Average		Average				Average
	Number		Remaining		Exercise		Number		Exercise
Range of Exercise Prices	Outstanding		Life		Price		Exercisable		Price

	(In thousands)						(In thousands)
$ 5.14 - $23.04		3,597		4.28 Years	$	17.58		3,597	$	17.58
$23.05 - $26.25		4,153		5.33 Years	$	23.83		3,631	$	23.94
$26.43 - $37.39		3,436		3.51 Years	$	28.65		2,443	$	29.21
$38.45 - $62.54		2,975		4.65 Years	$	39.14		1,123	$	38.97
$66.39 - $68.64		2,571		5.65 Years	$	66.41		121	$	66.45

		16,732		4.66 Years	$	32.74		10,915	$	25.04

A summary of restricted stock awards granted under each of these equity compensation plans as of December 31, 2005 is presented below:


		2005		2004		2003		Total

		(Shares in thousands, $ in millions, except
		per share amounts)
2005 Plan
	Shares granted		1,274		—		—		1,274
	Aggregate fair value	$	84		—		—	$	84
	Weighted average fair value per share	$	65.98		—		—	$	65.98
2003 Plan
	Shares granted		30		1,735		1,306		3,071
	Aggregate fair value	$	1	$	66	$	34	$	101
	Weighted average fair value per share	$	45.95	$	38.24	$	26.41	$	33.29
Total
	Shares granted		1,304		1,735		1,306		4,345
	Aggregate fair value	$	85	$	66	$	34	$	185
	Weighted average fair value per share	$	65.51	$	38.24	$	26.41	$	42.87


	*Shareholder Rights Plan*

Under Devon’s shareholder rights plan, stockholders have one half of one right for each share of common stock held. The rights become exercisable and separately transferable ten business days after (a) an announcement that a person has acquired, or obtained the right to acquire, 15% or more of the voting shares outstanding, or (b) commencement of a tender or exchange offer that could result in a person owning 15% or more of the voting shares outstanding.

Each right entitles its holder (except a holder who is the acquiring person) to purchase either (a) 1/100 of a share of Series A Preferred Stock for $185.00, subject to adjustment or, (b) Devon common stock with a value equal to twice the exercise price of the right, subject to adjustment to prevent dilution. In the event of certain merger or asset sale transactions with another party or transactions which would increase the equity ownership of a shareholder who then owned 15% or more of Devon, each Devon right will entitle its holder to purchase securities of the merging or acquiring party with a value equal to twice the exercise price of the right.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The rights, which have no voting power, expire on August 17, 2009. The rights may be redeemed by Devon for $0.01 per right until the rights become exercisable.


	*Dividends*

Dividends on Devon’s common stock were paid in 2005, 2004 and 2003 at a per share rate of $0.075, $0.05 and $0.025 per quarter, respectively.


10.	Financial Instruments

The following table presents the carrying amounts and estimated fair values of Devon’s financial instrument assets (liabilities) at December 31, 2005 and 2004.


	2005						2004

	Carrying			Fair			Carrying			Fair
	Amount			Value			Amount			Value

	(In millions)
Investment in Chevron Corporation common stock	$	805			805			745			745
Oil and gas price hedge agreements	$	—			—			(395	)		(395	)
Interest rate swap agreements	$	(22	)		(22	)		—			—
Embedded option in exchangeable debentures	$	(121	)		(121	)		(67	)		(67	)
Long-term debt	$	(6,619	)		(7,642	)		(7,964	)		(9,046	)

The following methods and assumptions were used to estimate the fair values of the financial instruments in the above table. The carrying values of cash and cash equivalents, short-term investments, accounts receivable and accounts payable (including income taxes payable and accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at December 31, 2005 and 2004.

Investment in Chevron Corporation common stock — The fair value of this investment is based on a quoted market price.

Oil and Gas Price Hedge Agreements — The fair values of the oil and gas price hedges were based on either (a) an internal discounted cash flow calculation, (b) quotes obtained from the counterparty to the hedge agreement or (c) quotes provided by brokers.

Interest Rate Swap Agreements — The fair values of the interest rate swaps are based on internal discounted cash flow calculations, using market quotes of future interest rates, or quotes obtained from counterparties.

Embedded Option in Exchangeable Debentures — The fair value of the embedded option is based on a quote obtained from a broker.

Long-term Debt — The fair values of the fixed-rate long-term debt are based on quotes obtained from brokers or by discounting the principal and interest payments at rates available for debt of similar terms and maturity. The fair values of the floating-rate long-term debt are estimated to approximate the carrying amounts due to the fact that the interest rates paid on such debt are generally set for periods of three months or less.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Interest Rate Swaps*

Devon has also entered into fixed-to -floating 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.


11.	Retirement Plans

Devon has various non-contributory defined benefit pension plans, including qualified plans (“Qualified Plans”) and nonqualified plans (“Supplemental Plans”). The Qualified Plans provide retirement benefits for U.S. and Canadian employees meeting certain age and service requirements. Benefits for the Qualified Plans are based on the employee’s years of service and compensation and are funded from assets held in the plans’ trusts.

Devon has a funding policy regarding the Qualified Plans such that it will contribute the amount of funds necessary so that the Qualified Plans’ assets will be approximately equal to the related accumulated benefit obligation. As of December 31, 2005 and 2004, the fair value of the Qualified Plans’ assets were $533 million and $456 million, respectively, which was $37 million and $11 million more, respectively, than the related accumulated benefit obligation. The actual amount of contributions required during future periods will depend on investment returns from the plan assets during the same period as well as changes in long-term interest rates.

The Supplemental Plans provide retirement benefits for certain employees whose benefits under the Qualified Plans are limited by income tax regulations. The Supplemental Plans’ benefits are based on the employee’s years of service and compensation. For certain Supplemental Plans, Devon has established trusts to fund these plans’ benefit obligations. The total values of these trusts were $59 million and $60 million at December 31, 2005 and 2004, respectively, and are included in non-current other assets in the consolidated balance sheets. For the remaining Supplemental Plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.

Devon also has defined benefit postretirement plans (“Postretirement Plans”) which provide benefits for substantially all employees. The Postretirement Plans provide medical and, in some cases, life insurance benefits and are, depending on the type of plan, either contributory or non-contributory. Benefit obligations for the Postretirement Plans are estimated based on future cost-sharing changes that are consistent with Devon’s expressed intent to increase, where possible, contributions from future retirees. Devon’s funding policy for the Postretirement Plans is to fund the benefits as they become payable with available cash and cash equivalents.


	*Benefit Obligations*

In 2005, Devon accelerated the date for actuarial measurement of its pension and postretirement benefit plans’ obligations from December 31 to November 30. Devon believes the one-month acceleration of the measurement date is a preferred change as it allows adequate time for Devon management to evaluate and report the actuarial pension and postretirement measurements, while facilitating the timely preparation of year-end financial statements. The effect of the change on the obligation and assets of the

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

pension and postretirement benefit plans did not have a material cumulative effect on the net periodic benefit cost or benefit obligation. Accordingly, all amounts reported in the tables below for the year ended December 31, 2005, are based on a measurement date of November 30, 2005, and amounts reported for the year ended December 31, 2004, are based upon a measurement date of December 31, 2004.

The following table presents the plans’ benefit obligations and the weighted-average actuarial assumptions used to calculate such obligations at December 31, 2005 and 2004. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans at December 31, 2005 and 2004 was $607 million and $542 million, respectively.


									Other
			Pension						Postretirement
			Benefits						Benefits

			2005			2004			2005			2004

			(In millions)
Change in benefit obligation:
	Benefit obligation at beginning of year		$	588			512			50			70
	Service cost			18			15			1			1
	Interest cost			34			32			3			3
	Participant contributions			—			—			2			1
	Amendments			1			1			—			(7	)
	Special termination benefits			—			1			—			—
	Foreign exchange rate changes			1			2			—			—
	Actuarial loss (gain)			50			52			6			(10	)
	Benefits paid			(26	)		(27	)		(8	)		(8	)

		Benefit obligation at end of year	$	666			588			54			50

Actuarial assumptions:
	Discount rate			5.72	%		5.74	%		5.75	%		5.75	%
	Rate of compensation increase			4.50	%		4.50	%		N/A			N/A

Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated benefit payments. This rate is based on high-quality bond yields, after allowing for call and default risk. High quality corporate bond yield indices, such as Moody’s Aa, are considered when selecting the discount rate.

For measurement purposes, a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2006. The rate was assumed to decrease one percent annually to 5% in the year 2011 and remain at that level thereafter. A one-percentage-point increase in assumed health care cost trend rates would increase the December 31, 2005 postretirement benefit obligation by $2 million, while a one-percentage-point decrease in the same rate would decrease the postretirement benefit obligation by $1 million.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Plan Assets*

The following table presents the plans’ assets at December 31, 2005 and 2004.


									Other
			Pension						Postretirement
			Benefits						Benefits

			2005			2004			2005			2004

			(In millions)
Change in plan assets:
	Fair value of plan assets at beginning of year		$	456			375			—			—
	Actual return on plan assets			37			40			—			—
	Employer contributions			65			70			6			7
	Participant contributions			—			—			2			1
	Transfer to defined contribution plan			—			(3	)		—			—
	Benefits paid			(26	)		(27	)		(8	)		(8	)
	Foreign exchange rate changes			1			1			—			—

		Fair value of plan assets at end of year	$	533			456			—			—

The plan assets for pension benefits in the table above excludes the assets held in trusts for the Supplemental Plans. However, employer contributions for pension benefits in the table above include $5 million in 2005 and $6 million in 2004 which were transferred from the trusts established for the Supplemental Plans.

Devon’s overall investment objective for its retirement plans’ assets is to achieve long-term growth of invested capital to ensure payments of retirement benefits obligations can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. At December 31, 2005, the target investment allocation for Devon’s 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. Derivatives or other speculative investments considered high-risk are generally prohibited.

The asset allocation for Devon’s retirement plans at December 31, 2005 and 2004, and the target allocation for 2006, by asset category, follows:


					Percentage of
					Plan Assets at
		Target			Year End
		Allocation
		2006			2005			2004

Equity securities			80	%		83	%		82	%
Debt securities			20	%		16	%		17	%
Other			—			1	%		1	%

	Total		100	%		100	%		100	%

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Funded Status*

The following table presents the funded status of the plans and the net amounts recognized in the consolidated balance sheets at December 31, 2005 and 2004.


									Other
									Postretirement
			Pension Benefits						Benefits

			2005			2004			2005			2004

			(In millions)
Net amounts recognized in consolidated balance sheets:
	Fair value of plan assets		$	533			456			—			—
	Benefit obligations			666			588			54			50

	Funded status			(133	)		(132	)		(54	)		(50	)
	Unrecognized net actuarial loss			195			155			7			1
	Unrecognized prior service cost (benefit)			6			5			(8	)		(9	)

		Net amounts recognized	$	68			28			(55	)		(58	)

Components of net amounts recognized in the consolidated balance sheets:
	Prepaid cost		$	144			98			—			—
	Accrued benefit cost			(109	)		(96	)		(55	)		(58	)
	Intangible asset			3			4			—			—
	Accumulated other comprehensive income			30			22			—			—

		Net amount recognized	$	68			28			(55	)		(58	)

During 2005, 2004 and 2003, the pre-tax change in the minimum pension liability increased (decreased) other comprehensive income by $(8) million, $61 million and $28 million, respectively.

Certain of Devon’s pension and postretirement plans have a projected benefit obligation in excess of plan assets at December 31, 2005 and 2004. The aggregate benefit obligation and fair value of plan assets for these plans is included below.


	December 31,

	2005		2004

	(In millions)
Projected benefit obligation	$	707		626
Fair value of plan assets	$	518		441

Certain of Devon’s pension plans have an accumulated benefit obligation in excess of plan assets at December 31, 2005 and 2004. The aggregate accumulated benefit obligation and fair value of plan assets for these plans is included below.


	December 31,

	2005		2004

	(In millions)
Accumulated benefit obligation	$	111		98
Fair value of plan assets		—		—

The plan assets included in the tables above exclude the Supplemental Plan trusts which had a total value of $59 million and $60 million at December 31, 2005 and 2004, respectively.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Net Periodic Cost*

The following table presents the plans’ net periodic benefit cost and the weighted-average actuarial assumptions used to calculate such cost for the years ended December 31, 2005, 2004 and 2003.


												Other
			Pension Benefits									Postretirement Benefits

			2005			2004			2003			2005			2004			2003

			(In millions)
Components of net periodic benefit cost:
	Service cost		$	18			15			12			1			1			1
	Interest cost			35			32			31			3			4			4
	Expected return on plan assets			(36	)		(30	)		(22	)		—			—			—
	Curtailment loss			—			—			1			—			—			—
	Termination benefits			—			1			—			—			—			—
	Amortization of prior service cost			1			1			1			(1	)		(1	)		—
	Recognized net actuarial loss			8			7			12			—			—			—

		Net periodic benefit cost	$	26			26			35			3			4			5

Actuarial assumptions:
	Discount rate			5.98	%		6.23	%		6.53	%		6.00	%		6.25	%		6.75	%
	Expected return on plan assets			8.40	%		8.34	%		8.25	%		N/A			N/A			N/A
	Rate of compensation increase			4.50	%		4.88	%		4.88	%		N/A			N/A			N/A

The expected rate of return on plan assets was determined by evaluating input from external consultants and economists as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types in such assets.

Assumed health care cost trend rates have a significant effect on the amounts reported for the other postretirement benefit plans. A one-percentage-point change in the assumed health care cost trend rates would affect the total service and interest cost by less than $1 million.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”) was signed into law. The Act introduces a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004 the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-2”). If the benefit provided is at least actuarially equivalent to Medicare Part D, FSP 106-2 requires companies to account for the effect of the subsidy on benefits attributable to past service as an actuarial experience gain that reduces the accumulated postretirement benefit obligation and for benefits attributable to current service as a reduction of the service cost included in net periodic benefit cost. FSP 106-2 is effective for the first interim period beginning after June 15, 2004. Because benefits provided to certain participants in the Postretirement Plans will be at least actuarially equivalent to Medicare Part D, Devon would be entitled to some subsidy. As a result, Devon reduced the accumulated postretirement benefit obligation at July 1, 2004, by $4 million and the net periodic postretirement benefit cost by $0.2 million for the year ended December 31, 2004. However, Devon made a decision during 2005 to not apply for the subsidy. Therefore, the amounts reported for 2005 do not reflect the impact of any potential subsidy.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Expected Cash Flows*

Information about the expected cash flows for the pension and other postretirement benefit plans follows:


				Other
		Pension		Postretirement
		Benefits		Benefits

		(In millions)
Employer contributions — 2006		$	7		5
Benefit payments:
	2006	$	29		5
	2007	$	30		5
	2008	$	32		5
	2009	$	33		5
	2010	$	35		5
	2011 - 2015	$	213		23

Expected employer contributions included in the table above include amounts related to Devon’s Qualified Plans, Supplemental Plans and Postretirement Plans. Of the benefits expected to be paid in 2006, $7 million is expected to be funded from the trusts established for the Supplemental Plans and $5 million is expected to be funded from Devon’s available cash and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.


	*Other Benefit Plans*

Devon has incurred certain postemployment benefits to former or inactive employees who are not retirees. These benefits include salary continuance, severance and disability health care and life insurance. The accrued postemployment benefit liability was approximately $5 million at December 31, 2005 and 2004.

Devon has a 401(k) Incentive Savings Plan which covers all domestic employees. At its discretion, Devon may match a certain percentage of the employees’ contributions to the plan. The matching percentage is determined annually by the Board of Directors. Devon’s matching contributions to the plan were $12 million, $11 million and $10 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Devon has defined contribution pension plans for its Canadian employees. Devon makes a contribution to each employee which is based upon the employee’s base compensation and classification. Such contributions are subject to maximum amounts allowed under the Income Tax Act (Canada). Devon also has a savings plan for its Canadian employees. Under the savings plan, Devon contributes a base percentage amount to all employees and the employee may elect to contribute an additional percentage amount (up to a maximum amount) which is matched by additional Devon contributions. During 2005, 2004 and 2003, Devon’s combined contributions to the Canadian defined contribution plan and the Canadian savings plan were $10 million, $9 million and $8 million, respectively.


12.	Commitments and Contingencies

Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals although actual amounts could differ materially from management’s estimate.


	*Environmental Matters*

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

Certain of Devon’s subsidiaries acquired in past mergers are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of December 31, 2005, Devon’s consolidated balance sheet included $4 million of non-current accrued liabilities, reflected in “Other liabilities,” related to these and other environmental remediation liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.


	*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 Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. Trial is set for February 2007 if the suit continues to advance. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.

Devon has been a defendant in certain private royalty owner litigation filed in Wyoming regarding deductibility of certain post production costs from royalties payable by Devon. A significant portion of such production is, or will be, transported through facilities owned by Thunder Creek Gas Services, L.L.C., of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

which Devon owns a 75% interest. During 2005, all of the litigation was resolved for amounts immaterial to Devon.


	*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, Devon received a subpoena issued by the SEC pursuant to a formal order of investigation. Devon has cooperated fully with the SEC’s previous requests for information in this inquiry and plans to continue to work with the SEC in connection with its formal investigation.


	*Hurricane Contingencies*

Devon maintains a comprehensive insurance program that includes coverage for physical damage to its offshore facilities caused by hurricanes. Devon’s insurance program also includes substantial business interruption coverage which Devon expects 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, Devon is 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 Devon will have production suspended, Devon expects its policy settlements will exceed repair costs and deductible amounts. This expectation is based 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. Should Devon’s policy settlements exceed repair costs and deductible amounts, the excess will be recognized as other income in the statement of operations.


	*Other Matters*

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


	*Commitments*

Devon has certain drilling and facility obligations under contractual agreements with third party service providers to procure drilling rigs and other drilling related services for developmental and exploratory drilling.

Devon has certain firm transportation agreements which represent “ship or pay” arrangements whereby Devon has committed to ship certain volumes of oil, gas and NGLs for a fixed transportation fee. Devon has entered into these agreements to aid the movement of its gas production to market. Devon expects to have sufficient production to utilize the majority of these transportation services.

Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in general and administrative expenses under operating leases, net of sub-lease income, was $35 million, $49 million and $51 million in 2005, 2004 and 2003, respectively.

Devon assumed two offshore platform spar leases through the 2003 Ocean merger. The spars are being used in the development of the Nansen and Boomvang fields in the Gulf of Mexico. The Boomvang field was divested as part of the 2005 property divestiture program. The Nansen operating lease is for a 20-year term and contains various options whereby Devon may purchase the lessors’ interests in the spar.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Total rental expense included in lease operating expenses under both the Nansen and Boomvang operating leases was $14 million, $17 million and $11 million in 2005, 2004 and 2003, respectively. Devon has guaranteed that the Nansen spar will have a residual value at the end of the operating leases 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 agreement. As a result of the sale of the Boomvang field, Devon is subleasing the Boomvang Spar. If the sublessee defaults on its obligation, Devon would be required to continue making the lease payments and any guaranteed payment required at the end of the term.

Devon has a floating, production, storage and offloading facility (“FPSO”) that is being used in the Panyu project offshore China and is being leased under operating lease arrangements. This lease expires in September 2009. Devon was also leasing an FPSO that is being used in the Zafiro field offshore Equatorial Guinea. Devon and the other working interest owners purchased this FPSO in the fourth quarter of 2005. Total rental expense included in lease operating expenses under both the China and Equatorial Guinea operating leases was $19 million, $20 million and $6 million in 2005, 2004 and 2003, respectively.

The following is a schedule by year of future minimum payments for drilling and facility obligations, firm transportation agreements and leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2005:


		Drilling
		and		Firm		Office and
		Facility		Transportation		Equipment		Spar		FPSO
Year Ending December 31,		Obligations		Agreements		Leases		Leases		Leases

		(In millions)
2006		$	666		102		35		11		7
2007			261		89		33		11		7
2008			180		66		28		11		7
2009			118		52		25		11		6
2010			93		38		23		11		—
Thereafter			—		131		53		150		—

	Total payments	$	1,318		478		197		205		27


13.	Reduction of Carrying Value of Oil and Gas Properties

Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” 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. The ceiling is determined separately by country. In calculating future net revenues, prices and costs used are those as of the end of the appropriate quarterly period. These prices are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including cash flow hedges in place. We had no such hedges outstanding at December 31, 2005.

The net book value, less related deferred tax liabilities, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred taxes, is written off as an expense. 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.

Under the purchase method of accounting for business combinations, acquired oil and gas properties are recorded at estimated fair value as of the date of purchase. Devon estimates such fair value using its

104

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

estimates of future oil, gas and NGL prices. In contrast, the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely. Accordingly, the resulting value from the ceiling calculation is not necessarily indicative of the fair value of the reserves.

During 2005 and 2003, Devon reduced the carrying value of its oil and gas properties due to full cost ceiling limitations, as well as due to unsuccessful exploratory activities. 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*

Devon’s interests in Angola were acquired through the Ocean Energy acquisition. Devon’s drilling program has been unsuccessful in Angola, resulting in no proven reserves for the country. After drilling a series of unsuccessful wells in the fourth quarter of 2005, Devon 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.


	*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, Devon revised Egyptian proved reserves downward. The Russian reduction was primarily the result of additional capital costs incurred as well as an

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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, Devon elected to discontinue certain exploratory activities in Ghana, certain properties in Brazil and other smaller concessions. After meeting the drilling and capital commitments on these properties, Devon determined that these properties did not meet its internal criteria to justify further investment. Accordingly, Devon recorded a charge associated with the impairment of these properties.


14.	Segment Information

Devon manages its business by country. As such, Devon identifies its segments based on geographic areas. Devon has three reportable segments: its operations in the U.S., its operations in Canada, and its international operations outside of North America. Substantially all of these segments’ operations involve oil and gas producing activities. Certain information regarding such activities for each segment is included in Note 15.

Following is certain financial information regarding Devon’s segments for 2005, 2004 and 2003. The revenues reported are all from external customers.


		U.S.		Canada		International		Total

		(In millions)
As of December 31, 2005:
Current assets		$	2,042		1,182		982		4,206
Property and equipment, net of accumulated depreciation, depletion and amortization			10,856		5,877		2,399		19,132
Goodwill			3,056		2,581		68		5,705
Other assets			1,213		17		—		1,230

	Total assets	$	17,167		9,657		3,449		30,273

Current liabilities		$	1,736		925		273		2,934
Long-term debt			2,986		2,971		—		5,957
Asset retirement obligation, long-term			320		261		37		618
Other liabilities			467		12		18		497
Deferred income taxes			2,994		2,008		403		5,405
Stockholders’ equity			8,664		3,480		2,718		14,862

	Total liabilities and stockholders’ equity	$	17,167		9,657		3,449		30,273

106

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			U.S.			Canada			International			Total

			(In millions)
Year Ended December 31, 2005:
Revenues:
	Oil sales		$	1,062			353			1,063			2,478
	Gas sales			3,929			1,814			41			5,784
	NGL sales			484			196			7			687
	Marketing and midstream revenues			1,780			12			—			1,792

		Total revenues		7,255			2,375			1,111			10,741

Expenses and other income, net:
	Lease operating expenses			710			498			137			1,345
	Production taxes			273			6			56			335
	Marketing and midstream operating costs and expenses			1,336			6			—			1,342
	Depreciation, depletion and amortization of oil and gas properties			1,137			570			324			2,031
	Depreciation and amortization of non-oil and gas properties			141			14			5			160
	Accretion of asset retirement obligation			25			16			3			44
	General and administrative expenses			245			59			(13	)		291
	Interest expense			224			309			—			533
	Effects of changes in foreign currency exchange rates			—			(1	)		(1	)		(2	)
	Change in fair value of derivative financial instruments			86			8			—			94
	Reduction of carrying value of oil and gas properties			—			—			212			212
	Other income, net			(176	)		(9	)		(11	)		(196	)

		Total expenses and other income, net		4,001			1,476			712			6,189

Earnings before income tax expense				3,254			899			399			4,552
Income tax expense (benefit):
	Current			890			106			242			1,238
	Deferred			195			217			(28	)		384

		Total income tax expense		1,085			323			214			1,622

Net earnings				2,169			576			185			2,930
Preferred stock dividends				10			—			—			10

Net earnings applicable to common stockholders			$	2,159			576			185			2,920

Capital expenditures			$	2,095			1,657			338			4,090

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		U.S.		Canada		International		Total

		(In millions)
As of December 31, 2004:
Current assets		$	2,196		1,109		567		3,872
Property and equipment, net of accumulated depreciation, depletion and amortization			11,011		5,741		2,594		19,346
Goodwill			3,061		2,508		68		5,637
Other assets			1,123		19		28		1,170

	Total assets	$	17,391		9,377		3,257		30,025

Current liabilities		$	1,933		800		367		3,100
Long-term debt			3,496		3,535		—		7,031
Asset retirement obligation, long-term			412		250		31		693
Other liabilities			400		21		17		438
Deferred income taxes			2,853		1,805		431		5,089
Stockholders’ equity			8,297		2,966		2,411		13,674

	Total liabilities and stockholders’ equity	$	17,391		9,377		3,257		30,025

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			U.S.			Canada			International			Total

			(In millions)
Year Ended December 31, 2004:
Revenues:
	Oil sales		$	976			299			927			2,202
	Gas sales			3,261			1,437			34			4,732
	NGL sales			405			143			6			554
	Marketing and midstream revenues			1,688			13			—			1,701

		Total revenues		6,330			1,892			967			9,189

Expenses and other income, net:
	Lease operating expenses			714			438			128			1,280
	Production taxes			220			5			30			255
	Marketing and midstream operating costs and expenses			1,333			6			—			1,339
	Depreciation, depletion and amortization of oil and gas properties			1,242			522			377			2,141
	Depreciation and amortization of non-oil and gas properties			130			14			5			149
	Accretion of asset retirement obligation			27			15			2			44
	General and administrative expenses			221			56			—			277
	Interest expense			197			278			—			475
	Effects of changes in foreign currency exchange rates			—			(22	)		(1	)		(23	)
	Change in fair value of derivative financial instruments			63			(1	)		—			62
	Other income, net			(81	)		(17	)		(5	)		(103	)

		Total expenses and other income, net		4,066			1,294			536			5,896

Earnings before income tax expense				2,264			598			431			3,293
Income tax expense (benefit):
	Current			483			49			220			752
	Deferred			240			149			(34	)		355

		Total income tax expense		723			198			186			1,107

Net earnings				1,541			400			245			2,186
Preferred stock dividends				10			—			—			10

Net earnings applicable to common stockholders			$	1,531			400			245			2,176

Capital expenditures			$	1,785			975			343			3,103

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			U.S.			Canada			International			Total

			(In millions)
Year Ended December 31, 2003:
Revenues:
	Oil sales		$	861			318			409			1,588
	Gas sales			2,652			1,222			23			3,897
	NGL sales			289			114			4			407
	Marketing and midstream revenues			1,443			17			—			1,460

		Total revenues		5,245			1,671			436			7,352

Expenses and other income, net:
	Lease operating expenses			617			392			69			1,078
	Production taxes			194			3			7			204
	Marketing and midstream operating costs and expenses			1,165			9			—			1,174
	Depreciation, depletion and amortization of oil and gas properties			1,084			389			195			1,668
	Depreciation and amortization of non-oil and gas properties			111			10			4			125
	Accretion of asset retirement obligation			22			13			1			36
	General and administrative expenses			252			43			12			307
	Expenses related to mergers			7			—			—			7
	Reduction in carrying value of oil and gas properties			—			—			111			111
	Interest expense			211			285			6			502
	Effects of changes in foreign currency exchange rates			—			(69	)		—			(69	)
	Change in fair value of derivative financial instruments			(2	)		1			—			(1	)
	Other income, net			(19	)		(8	)		(8	)		(35	)

		Total expenses and other income, net		3,642			1,068			397			5,107

Earnings before income tax expense (benefit) and cumulative effect of change in accounting principle				1,603			603			39			2,245
Income tax expense (benefit):
	Current			131			(9	)		71			193
	Deferred			377			(16	)		(40	)		321

		Total income tax expense (benefit)		508			(25	)		31			514

Earnings before cumulative effect of change in accounting principle				1,095			628			8			1,731
Cumulative effect of change in accounting principle				11			5			—			16

Net earnings				1,106			633			8			1,747
Preferred stock dividends				10			—			—			10

Net earnings applicable to common stockholders			$	1,096			633			8			1,737

Capital expenditures			$	1,579			704			304			2,587

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


15.	Supplemental Information on Oil and Gas Operations (Unaudited)

The following supplemental unaudited information regarding the oil and gas activities of Devon is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and SFAS No. 69, Disclosures About Oil and Gas Producing Activities.

Costs Incurred

The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities:


			Total

			Year Ended December 31,

			2005		2004		2003

			(In millions)
Property acquisition costs:
	Proved properties		$	54		38		4,343

	Unproved properties — business combinations			—		—		1,063
	Unproved properties — other acquisitions			349		141		87

		Total unproved properties		349		141		1,150
Exploration costs				931		735		714
Development costs				2,805		1,938		1,864

		Costs incurred	$	4,139		2,852		8,071


			Domestic

			Year Ended December 31,

			2005		2004		2003

			(In millions)
Property acquisition costs:
	Proved properties		$	5		27		2,697

	Unproved properties — business combinations			—		—		551
	Unproved properties — other acquisitions			106		75		48

		Total unproved properties		106		75		599
Exploration costs				422		335		343
Development costs				1,597		1,163		1,193

		Costs incurred	$	2,130		1,600		4,832

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			Canada

			Year Ended
			December 31,

			2005		2004		2003

			(In millions)
Property acquisition costs:
	Proved properties		$	49		11		26

	Unproved properties — business combinations			—		—		—
	Unproved properties — other acquisitions			239		52		39

		Total unproved properties		239		52		39
Exploration costs				361		272		214
Development costs				1,020		625		491

		Costs incurred	$	1,669		960		770


			International

			Year Ended
			December 31,

			2005		2004		2003

			(In millions)
Property acquisition costs:
	Proved properties		$	—		—		1,620

	Unproved properties — business combinations			—		—		512
	Unproved properties — other acquisitions			4		14		—

		Total unproved properties...		4		14		512
Exploration costs				148		128		157
Development costs				188		150		180

		Costs incurred	$	340		292		2,469

Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses which are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $189 million, $172 million and $140 million in the years 2005, 2004 and 2003, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $70 million, $70 million and $50 million in the years 2005, 2004 and 2003, respectively.

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	*Results of Operations for Oil and Gas Producing Activities*

The following tables include revenues and expenses associated directly with Devon’s oil and gas producing activities, including general and administrative expenses directly related to such producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.


	Total

	Year Ended December 31,

	2005			2004			2003

	(In millions, except per
	equivalent barrel amounts)
Oil, gas and NGL sales	$	8,949			7,488			5,892
Production and operating expenses		(1,680	)		(1,535	)		(1,282	)
Depreciation, depletion and amortization		(2,031	)		(2,141	)		(1,668	)
Accretion of asset retirement obligation		(44	)		(44	)		(36	)
General and administrative expenses directly related to oil and gas producing activities		(43	)		(38	)		(48	)
Reduction of carrying value of oil and gas properties		(212	)		—			(111	)
Income tax expense		(1,806	)		(1,288	)		(895	)

Results of operations for oil and gas producing activities	$	3,133			2,442			1,852

Depreciation, depletion and amortization per equivalent barrel of production	$	8.99			8.54			7.33


	Domestic

	Year Ended December 31,

	2005			2004			2003

	(In millions, except per
	equivalent barrel amounts)
Oil, gas and NGL sales	$	5,475			4,642			3,802
Production and operating expenses		(983	)		(934	)		(811	)
Depreciation, depletion and amortization		(1,137	)		(1,242	)		(1,084	)
Accretion of asset retirement obligation		(25	)		(27	)		(22	)
General and administrative expenses directly related to oil and gas producing activities		(23	)		(22	)		(27	)
Income tax expense		(1,166	)		(827	)		(775	)

Results of operations for oil and gas producing activities	$	2,141			1,590			1,083

Depreciation, depletion and amortization per equivalent barrel of production	$	8.35			8.23			7.42

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Canada

	Year Ended December 31,

	2005			2004			2003

	(In millions, except per
	equivalent barrel amounts)
Oil, gas and NGL sales	$	2,363			1,879			1,654
Production and operating expenses		(504	)		(443	)		(395	)
Depreciation, depletion and amortization		(570	)		(522	)		(388	)
Accretion of asset retirement obligation		(16	)		(15	)		(13	)
General and administrative expenses directly related to oil and gas producing activities		(20	)		(16	)		(15	)
Income tax expense		(426	)		(275	)		(89	)

Results of operations for oil and gas producing activities	$	827			608			754

Depreciation, depletion and amortization per equivalent barrel of production	$	9.20			8.00			6.17


	International

	Year Ended December 31,

	2005			2004			2003

	(In millions, except per
	equivalent barrel amounts)
Oil, gas and NGL sales	$	1,111			967			436
Production and operating expenses		(193	)		(158	)		(76	)
Depreciation, depletion and amortization		(324	)		(377	)		(196	)
Accretion of asset retirement obligation		(3	)		(2	)		(1	)
General and administrative expenses directly related to oil and gas producing activities		—			—			(6	)
Reduction of carrying value of oil and gas properties		(212	)		—			(111	)
Income tax expense		(214	)		(186	)		(31	)

Results of operations for oil and gas producing activities	$	165			244			15

Depreciation, depletion and amortization per equivalent barrel of production	$	11.61			10.88			10.52


	*Quantities of Oil and Gas 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 revenues which were

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

estimated by Devon 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.

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

Set forth below is a summary of the changes in the net quantities of crude oil, natural gas and natural gas liquids reserves for each of the three years ended December 31, 2005.


		Total

								Natural
								Gas
		Oil			Gas			Liquids			Total
		(MMBbls)			(Bcf)			(MMBbls)			(MMBoe)

Proved reserves as of December 31, 2002			444			5,836			192			1,609
	Revisions due to prices		(4	)		64			2			8
	Revisions other than price		(5	)		(73	)		(2	)		(19	)
	Extensions and discoveries		29			834			20			188
	Purchase of reserves		262			1,650			19			556
	Production		(62	)		(863	)		(22	)		(228	)
	Sale of reserves		(3	)		(132	)		—			(25	)

Proved reserves as of December 31, 2003			661			7,316			209			2,089
	Revisions due to prices		(84	)		39			1			(76	)
	Revisions other than price		19			30			21			45
	Extensions and discoveries		78			988			25			268
	Purchase of reserves		1			14			—			3
	Production		(78	)		(891	)		(24	)		(251	)
	Sale of reserves		(1	)		(2	)		—			(1	)

Proved reserves as of December 31, 2004			596			7,494			232			2,077
	Revisions due to prices		(16	)		78			4			1
	Revisions other than price		22			(3	)		16			38
	Extensions and discoveries		167			1,220			30			401
	Purchase of reserves		2			10			—			4
	Production		(64	)		(827	)		(24	)		(226	)
	Sale of reserves		(58	)		(676	)		(12	)		(183	)

Proved reserves as of December 31, 2005			649			7,296			246			2,112

Proved developed reserves as of:
	December 31, 2002		260			4,618			150			1,180
	December 31, 2003		408			5,980			179			1,584
	December 31, 2004		411			6,219			204			1,652
	December 31, 2005		363			6,111			216			1,599

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		Domestic

								Natural
								Gas
		Oil			Gas			Liquids			Total
		(MMBbls)			(Bcf)			(MMBbls)			(MMBoe)

Proved reserves as of December 31, 2002			147			3,552			146			885
	Revisions due to prices		3			93			3			21
	Revisions other than price		(9	)		(36	)		(4	)		(19	)
	Extensions and discoveries		12			510			14			111
	Purchase of reserves		92			1,474			19			357
	Production		(31	)		(589	)		(17	)		(146	)
	Sale of reserves		(2	)		(120	)		—			(22	)

Proved reserves as of December 31, 2003			212			4,884			161			1,187
	Revisions due to prices		5			8			1			8
	Revisions other than price		2			62			23			35
	Extensions and discoveries		16			578			16			129
	Purchase of reserves		—			8			—			1
	Production		(31	)		(602	)		(19	)		(151	)
	Sale of reserves		(1	)		(2	)		—			(1	)

Proved reserves as of December 31, 2004			203			4,936			182			1,208
	Revisions due to prices		6			58			3			19
	Revisions other than price		2			238			19			61
	Extensions and discoveries		16			793			20			169
	Purchase of reserves		—			—			—			—
	Production		(25	)		(555	)		(18	)		(136	)
	Sale of reserves		(29	)		(306	)		(9	)		(89	)

Proved reserves as of December 31, 2005			173			5,164			197			1,232

Proved developed reserves as of:
	December 31, 2002		135			2,802			117			719
	December 31, 2003		171			3,935			136			964
	December 31, 2004		168			4,105			161			1,014
	December 31, 2005		149			4,343			175			1,049

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		Canada

								Natural
								Gas
		Oil			Gas			Liquids			Total
		(MMBbls)			(Bcf)			(MMBbls)			(MMBoe)

Proved reserves as of December 31, 2002			149			2,284			46			576
	Revisions due to prices		1			(28	)		(1	)		(5	)
	Revisions other than price		(5	)		(5	)		2			(4	)
	Extensions and discoveries		16			324			6			76
	Purchase of reserves		2			1			—			2
	Production		(14	)		(267	)		(5	)		(63	)
	Sale of reserves		(1	)		(12	)		—			(3	)

Proved reserves as of December 31, 2003			148			2,297			48			579
	Revisions due to prices		(43	)		32			—			(38	)
	Revisions other than price		5			(46	)		(2	)		(5	)
	Extensions and discoveries		50			410			9			127
	Purchase of reserves		1			6			—			2
	Production		(14	)		(279	)		(5	)		(65	)
	Sale of reserves		—			—			—			—

Proved reserves as of December 31, 2004			147			2,420			50			600
	Revisions due to prices		—			22			1			4
	Revisions other than price		2			(242	)		(3	)		(41	)
	Extensions and discoveries		144			427			10			225
	Purchase of reserves		2			10			—			4
	Production		(13	)		(261	)		(6	)		(62	)
	Sale of reserves		(29	)		(370	)		(3	)		(94	)

Proved reserves as of December 31, 2005			253			2,006			49			636

Proved developed reserves as of:
	December 31, 2002		119			1,816			33			455
	December 31, 2003		123			1,964			43			493
	December 31, 2004		123			2,043			43			507
	December 31, 2005		103			1,708			41			429

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		International

								Natural
								Gas
		Oil			Gas			Liquids		Total
		(MMBbls)			(Bcf)			(MMBbls)		(MMBoe)

Proved reserves as of December 31, 2002			148			—			—		148
	Revisions due to prices		(8	)		(1	)		—		(8	)
	Revisions other than price		9			(32	)		—		4
	Extensions and discoveries		1			—			—		1
	Purchase of reserves		168			175			—		197
	Production		(17	)		(7	)		—		(19	)
	Sale of reserves		—			—			—		—

Proved reserves as of December 31, 2003			301			135			—		323
	Revisions due to prices		(46	)		(1	)		—		(46	)
	Revisions other than price		12			14			—		15
	Extensions and discoveries		12			—			—		12
	Purchase of reserves		—			—			—		—
	Production		(33	)		(10	)		—		(35	)
	Sale of reserves		—			—			—		—

Proved reserves as of December 31, 2004			246			138			—		269
	Revisions due to prices		(22	)		(2	)		—		(22	)
	Revisions other than price		18			1			—		18
	Extensions and discoveries		7			—			—		7
	Purchase of reserves		—			—			—		—
	Production		(26	)		(11	)		—		(28	)
	Sale of reserves		—			—			—		—

Proved reserves as of December 31, 2005			223			126			—		244

Proved developed reserves as of:
	December 31, 2002		6			—			—		6
	December 31, 2003		114			81			—		127
	December 31, 2004		120			71			—		131
	December 31, 2005		111			60			—		121

The preceding International quantities of reserves are attributable to production sharing contracts with various foreign governments.

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	*Standardized Measure of Discounted Future Net Cash Flows*

The accompanying tables reflect the standardized measure of discounted future net cash flows relating to Devon’s interest in proved reserves:


		Total

		December 31,

		2005			2004			2003

		(In millions)
Future cash inflows		$	94,648			67,035			60,562
Future costs:
	Development		(5,852	)		(4,250	)		(3,693	)
	Production		(23,840	)		(18,395	)		(16,232	)
Future income tax expense			(22,007	)		(14,241	)		(12,078	)

Future net cash flows			42,949			30,149			28,559
10% discount to reflect timing of cash flows			(19,375	)		(14,064	)		(12,638	)

Standardized measure of discounted future net cash flows		$	23,574			16,085			15,921


		Domestic

		December 31,

		2005			2004			2003

		(In millions)
Future cash inflows		$	55,954			39,214			36,602
Future costs:
	Development		(2,954	)		(2,208	)		(2,028	)
	Production		(14,882	)		(12,093	)		(10,788	)
Future income tax expense			(13,061	)		(7,989	)		(6,848	)

Future net cash flows			25,057			16,924			16,938
10% discount to reflect timing of cash flows			(11,781	)		(7,550	)		(7,435	)

Standardized measure of discounted future net cash flows		$	13,276			9,374			9,503


		Canada

		December 31,

		2005			2004			2003

		(In millions)
Future cash inflows		$	26,277			18,483			15,517
Future costs:
	Development		(1,984	)		(1,353	)		(1,051	)
	Production		(6,344	)		(4,285	)		(3,585	)
Future income tax expense			(5,986	)		(4,200	)		(3,316	)

Future net cash flows			11,963			8,645			7,565
10% discount to reflect timing of cash flows			(5,332	)		(4,764	)		(3,442	)

Standardized measure of discounted future net cash flows		$	6,631			3,881			4,123

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		International

		December 31,

		2005			2004			2003

		(In millions)
Future cash inflows		$	12,417			9,338			8,443
Future costs:
	Development		(914	)		(689	)		(614	)
	Production		(2,614	)		(2,017	)		(1,859	)
Future income tax expense			(2,960	)		(2,052	)		(1,914	)

Future net cash flows			5,929			4,580			4,056
10% discount to reflect timing of cash flows			(2,262	)		(1,750	)		(1,761	)

Standardized measure of discounted future net cash flows		$	3,667			2,830			2,295

Future cash inflows are computed by applying year-end prices (averaging $45.50 per barrel of oil, $7.84 per Mcf of gas and $32.46 per barrel of natural gas liquids at December 31, 2005) to the year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements in existence at year-end.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Of the $5.9 billion of future development costs, $1.3 billion, $0.9 billion and $0.6 billion are estimated to be spent in 2006, 2007 and 2008, respectively.

Future development costs include not only development costs, but also future dismantlement, abandonment and rehabilitation costs. Included as part of the $5.9 billion of future development costs are $1.2 billion of future dismantlement, abandonment and rehabilitation costs.

Future production costs include general and administrative expenses directly related to oil and gas producing activities. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.

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	*Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows*

Principal changes in the standardized measure of discounted future net cash flows attributable to Devon’s proved reserves are as follows:


	Year Ended December 31,

	2005			2004			2003

	(In millions)
Beginning balance	$	16,085			15,921			10,365
Oil, gas and NGL sales, net of production costs		(7,226	)		(5,915	)		(4,562	)
Net changes in prices and production costs		11,787			2,749			2,645
Extensions, discoveries, and improved recovery, net of future development costs		6,200			3,103			2,218
Purchase of reserves, net of future development costs		68			32			5,763
Development costs incurred during the period which reduced future development costs		768			684			1,022
Revisions of quantity estimates		(788	)		(1,132	)		(728	)
Sales of reserves in place		(2,936	)		(13	)		(307	)
Accretion of discount		2,343			2,265			1,531
Net change in income taxes		(4,692	)		(1,782	)		(2,305	)
Other, primarily changes in timing and foreign exchange rates		1,965			173			279

Ending balance	$	23,574			16,085			15,921


16.	Supplemental Quarterly Financial Information (Unaudited)

Following is a summary of the unaudited interim results of operations for the years ended December 31, 2005 and 2004.


		2005

		First		Second		Third		Fourth		Full
		Quarter		Quarter		Quarter		Quarter		Year

		(In millions, except per share amounts)
Oil, gas and NGL sales		$	1,935		2,079		2,299		2,636		8,949
Total revenues		$	2,351		2,468		2,704		3,218		10,741
Net earnings		$	563		653		744		970		2,930
Net earnings per common share:
	Basic	$	1.17		1.40		1.66		2.18		6.38
	Diluted	$	1.14		1.38		1.63		2.14		6.26


		2004

		First		Second		Third		Fourth		Full
		Quarter		Quarter		Quarter		Quarter		Year

		(In millions, except per share amounts)
Oil, gas and NGL sales		$	1,821		1,842		1,859		1,966		7,488
Total revenues		$	2,238		2,219		2,267		2,465		9,189
Net earnings		$	494		502		517		673		2,186
Net earnings per common share:
	Basic	$	1.03		1.04		1.06		1.38		4.51
	Diluted	$	1.00		1.01		1.03		1.35		4.38

121

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The fourth quarter of 2005 includes a $212 million reduction of carrying value of oil and gas properties and a $14 million income tax benefit due to a statutory rate reduction in Canada. The after-tax effect of the reduction of carrying value was $161 million, or $0.36 per share. The per share effect of the rate reduction tax benefit was $0.03.

The second and fourth quarters of 2004 include a $28 million and $8 million income tax benefit, respectively, due to statutory rate reductions of Canadian tax rates. The per share effect of these tax benefits were $0.06 and $0.01 in the second and fourth quarters of 2004, respectively.

122


Item 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure*

Not Applicable.


Item 9A.	*Controls and Procedures*

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, Devon’s principal executive and principal financial officers have concluded that Devon’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 2005 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

Devon’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, Devon conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework which was completed on February 10, 2006, management concluded that its internal control over financial reporting was effective as of December 31, 2005.

Management’s assessment of the effectiveness of Devon’s internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting firm who audited Devon’s consolidated financial statements as of and for the year ended December 31, 2005, as stated in their report which is included herein.

Changes in Internal Control Over Financial Reporting

There was no change in Devon’s internal control over financial reporting during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

123

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Devon Energy Corporation:

We have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting that Devon Energy Corporation maintained effective 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). Devon Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Devon Energy Corporation maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Devon Energy Corporation maintained, in all material respects, effective 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).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 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, and our report dated February 28, 2006 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Oklahoma City, Oklahoma

February 28, 2006

124

Item 9B. Other Information

Not applicable.

125

PART III


Item 10.	*Directors and Executive Officers of the Registrant*

The information called for by this Item 10 is incorporated hereby by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2006.


Item 11.	*Executive Compensation*

The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2006.


Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*

The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2006.


Item 13.	*Certain Relationships and Related Transactions*

The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2006.


Item 14.	*Principal Accountant Fees and Services*

The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2006.

126

PART IV


Item 15.	*Exhibits and Financial Statement Schedules*

(a) The following documents are filed as part of this report:


	1. Consolidated Financial Statements

Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at Item 8 in this report.


	2. Consolidated Financial Statement Schedules

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.


	3. Exhibits


Exhibit No.			Description

	2	.1	Agreement and Plan of Merger, dated as of February 23, 2003, by and among Registrant, Devon NewCo Corporation, and Ocean Energy, Inc. (incorporated by reference to Registrant’s Amendment No. 1 to Form S-4 Registration No. 333-103679, filed March 20, 2003).

	2	.2	Amended and Restated Agreement and Plan of Merger, dated as of August 13, 2001, by and among Registrant, Devon NewCo Corporation, Devon Holdco Corporation, Devon Merger Corporation, Mitchell Merger Corporation and Mitchell Energy & Development Corp. (incorporated by reference to Annex A to Registrant’s Joint Proxy Statement/ Prospectus of Form S-4 Registration Statement No. 333-68694 as filed August 30, 2001).

	2	.3	Offer to Purchase for Cash and Directors’ Circular dated September 6, 2001 (incorporated by reference to Registrant’s and Devon Acquisition Corporation’s Schedule 14D-1F filing, filed September 6, 2001).

	2	.4	Pre-Acquisition Agreement, dated as of August 31, 2001, between Registrant and Anderson Exploration Ltd. (incorporated by reference to Exhibit 2.2 to Registrant’s Registration Statement on Form S-4, File No. 333-68694 as filed September 14, 2001).

	2	.5	Agreement and Plan of Merger by and among Registrant, Devon Merger Co. and Santa Fe Snyder Corporation dated as of May 25, 2000 (incorporated by reference to Registrant’s Registration Statement on Form S-4, File No. 333-39908).

	2	.6	Amendment No. One, dated as of July 11, 2000, to Agreement and Plan of Merger by and among Registrant, Devon Merger Co. and Santa Fe Snyder Corporation dated as of May 25, 2000 (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on July 12, 2000).

	2	.7	Amended and Restated Agreement and Plan of Merger among Registrant, Devon Energy Corporation (Oklahoma), Devon Oklahoma Corporation and PennzEnergy Company dated as of May 19, 1999 (incorporated by reference to Exhibit 2.1 to Registrant’s Form S-4, File No. 333-82903).

	2	.8	Amended and Restated Combination Agreement between Registrant and Northstar Energy Corporation dated as of June 29, 1998 (incorporated by reference to Annex B to Registrant’s definitive proxy statement for a special meeting of shareholders, filed November 6, 1998).

	3	.1	Registrant’s Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-K filed on March 9, 2005).

	3	.2	Registrant’s Bylaws.

	4	.1	Rights Agreement dated as of August 17, 1999 between Registrant and BankBoston, N.A. (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed on August 18, 1999).

127


Exhibit No.			Description

	4	.2	Amendment to Rights Agreement, dated as of May 25, 2000, by and between Registrant and Fleet National Bank (f/k/a BankBoston, N.A.) (incorporated by reference to Exhibit 4.2 to Registrant’s definitive proxy statement for a special meeting of shareholders filed on July 21, 2000).

	4	.3	Amendment to Rights Agreement, dated as of October 4, 2001, by and between Registrant and Fleet National Bank (f/k/a Bank Boston, N.A.) (incorporated by reference to Exhibit 99.1 to Registrant’s Form 8-K filed on October 11, 2001).

	4	.4	Amendment to Rights Agreement, dated September 13, 2002, between Registrant and Wachovia Bank, N.A. (incorporated by reference to Exhibit 4.9 to Registrant’s Registration Statement on Form S-3 File Nos. 333-83156, 333-83156-1, and 333-83156-2 as filed on October 4, 2002).

	4	.5	Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York, as Trustee, relating to senior debt securities issuable by Registrant (the “Senior Indenture”) (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K filed April 9, 2002).

	4	.6	Supplemental Indenture No. 1, dated as of March 25, 2002, between Registrant and The Bank of New York, as Trustee, relating to the 7.95% Senior Debentures due 2032 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed on April 9, 2002).

	4	.7	Supplemental Indenture No. 2, dated as of August 4, 2003, between Registrant and The Bank of New York, as Trustee, relating to the 2.75% Senior Notes due 2006 (incorporated by reference to Exhibit 4.8 of Registrant’s Form 10-K filed on March 5, 2003).

	4	.8	Indenture dated as of October 3, 2001, by and among Devon Financing Corporation, U.L.C. (as issuer), Registrant (as guarantor) and JP Morgan Chase Bank, formerly The Chase Manhattan Bank (as trustee), relating to the 6.875% Senior Notes due 2011 and the 7.875% Debentures due 2031 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4, File No. 333-68694 as filed October 31, 2001).

	4	.9	Indenture dated as of December 15, 1992 between Registrant (as successor by merger to PennzEnergy Company, formerly Pennzoil Company) and Texas Commerce Bank National Association, Trustee, relating to the 4.90% Exchangeable Senior Debentures due 2008 and the 4.95% Exchangeable Senior Debentures due 2008 (incorporated by reference to Exhibit 4(o) to Pennzoil Company’s Form 10-K filed March 10, 1993 (SEC File No. 1-5591)).

	4	.10	First Supplemental Indenture dated as of January 13, 1993 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy Company, formerly Pennzoil Company) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4(p) to Pennzoil Company’s Form 10-K for the year ended December 31, 1992).

	4	.11	Second Supplemental Indenture dated as of October 12, 1993 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy Company, formerly Pennzoil Company) and Chase Bank of Texas, National Association, as Trustee, (incorporated by reference to Exhibit 4(i) to Pennzoil Company’s Form 10-K for the year ended December 31, 1993) .

	4	.12	Third Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy Company, formerly Pennzoil Company) and JP Morgan Chase Bank, formerly Chase Bank of Texas, National Association, as Trustee, supplements the terms of the 4.90% Exchangeable Senior Debentures due 2008 (incorporated by reference to Exhibit 4(g) to PennzEnergy Company’s Form 10-K for the year ended December 31, 1998).

128


Exhibit No.			Description

	4	.13	Fourth Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy Company, formerly Pennzoil Company) and JP Morgan Chase Bank, formerly Chase Bank of Texas, National Association, as Trustee, supplements the terms of the 4.95% Exchangeable Senior Debentures due 2008 (incorporated by reference to Exhibit 4(h) to PennzEnergy Company’s Form 10-K for the year ended December 31, 1998).

	4	.14	Fifth Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy Company, formerly Pennzoil Company) and JP Morgan Chase Bank, formerly Chase Bank of Texas, National Association, Trustee, supplements the terms of the 4.90% Exchangeable Senior Debentures due 2008 and the 4.95% Exchangeable Senior Debentures due 2008 (incorporated by reference to Exhibit 4.7 to Registrant’s Form 8-K filed on August 18, 1999).

	4	.15	Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy Company, formerly Pennzoil Company) and Mellon Bank, N.A., Trustee (incorporated by reference to Exhibit 4(a) to Pennzoil Company’s Form 10-Q for the quarter ended June 30, 1986 (SEC File No. 1-5591)).

	4	.16	First Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy Company, formerly Pennzoil Company) and JP Morgan Chase Bank, formerly Chase Bank of Texas, National Association, Trustee, supplementing the terms of the 10.625% Debentures due 2001, 10.125% Debentures due 2009, 9.625% Notes due 1999 and 10.25% Debentures due 2005 (incorporated by reference to Exhibit 4.8 to Registrant’s Form 8-K filed on August 18, 1999).

	4	.17	Senior Indenture dated as of September 28, 2001 between Ocean Energy, Inc. and The Bank of New York, As Trustee (incorporated by reference to Exhibit 4.1 to Ocean Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 28, 2001). Officer’s Certificate establishing the terms of the 7.25% Senior Notes due 2011, including the form of global note relating thereto (incorporated by reference to Exhibit 4.2 to Ocean Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 28, 2001).

	4	.18	Officers’ Certificate evidencing the terms of the 4.375% Senior Notes due 2007, including the form of global note relating thereto (incorporated by reference to Exhibit 4.1 to Ocean Energy, Inc.’s Current Report on Form 8-K filed with the SEC on September 17, 2002).

	4	.19	First Supplemental Indenture, dated December 31, 2005 to Indenture dated as of September 28, 2001 among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor and The Bank of New York Trust Company, N.A., as Trustee, relating to the 4 ³ / 8 % Senior Notes due 2007 and the 7 ¹ / 4 % Senior Notes due 2011.

	4	.20	Indenture dated as of July 8, 1998 among Ocean Energy, Inc., its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 10.24 to the Form 10-Q for the period ended June 30, 1998 of Ocean Energy, Inc. (Registration No. 0-25058)).

	4	.21	First Supplemental Indenture, dated March 30, 1999 to Indenture dated as of July 8, 1998 among Ocean Energy, Inc., its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.5 to Ocean Energy, Inc.’s Form 10-Q for the period ended March 31, 1999).

	4	.22	Second Supplemental Indenture, dated as of May 9, 2001 to Indenture dated as of July 8, 1998 among Ocean Energy, Inc., its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 99.2 to Ocean Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 14, 2001) .

129


Exhibit No.			Description

	4	.23	Third Supplemental Indenture, dated January 23, 2006 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor and Wells Fargo Bank Minnesota, National Association, as Trustee, relating to the 8.25% Senior Notes due 2018.

	4	.24	Senior Indenture dated September 1, 1997, among Ocean Energy, Inc. and The Bank of New York, as Trustee, and Specimen of 7.50% Senior Notes Due 2027 (incorporated by reference to Ocean Energy’s Exhibit 4.4 to Ocean Energy’s Annual Report on Form 10-K for the year ended December 31, 1997)).

	4	.25	First Supplemental Indenture, dated as of March 30, 1999 to Senior Indenture dated as of September 1, 1997, among Ocean Energy, Inc. and The Bank of New York, as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 4.10 to Ocean Energy’s Form 10-Q for the period ended March 31, 1999).

	4	.26	Second Supplemental Indenture, dated as of May 9, 2001 to Senior Indenture dated as of September 1, 1997, among Ocean Energy, Inc. and The Bank of New York, as Trustee, relating to the 7.50% Senior Notes (incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 14, 2001).

	4	.27	Third Supplemental Indenture, dated December 31, 2005 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor, and The Bank of New York Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes.

	10	.1	Amended and Restated Investor Rights Agreement, dated as of August 13, 2001, by and among Registrant, Devon Holdco Corporation, George P. Mitchell and Cynthia Woods Mitchell (attached as Annex C to the Joint Proxy Statement/ Prospectus of Form S-4 Registration Statement No. 333-68694 as filed August 30, 2001).

	10	.2	Credit Agreement dated as of April 8, 2004, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as Canadian Borrowers, Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/ C Issuer, JPMorgan Chase Bank as Syndication Agent, Bank of Montreal, D/ B/ A “Harris Nesbitt”, Royal Bank of Canada, Wachovia Bank, National Association as Co-Documentation Agents and The Other Lenders Party Hereto, Banc of America Securities LLC and J.P. Morgan Securities Inc. as Joint Lead Arrangers and Book Managers for the $1.5 billion five-year revolving credit facility (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 7, 2004).

	10	.3	First Amendment to Credit Agreement dated as of March 4, 2005, by and among Registrant, Northstar Energy Corporation and Devon Canada Corporation, Bank of America, N.A., (“as Administrative Agent”), and the Lenders signatory thereto (incorporated by reference to Exhibit 10.3 of Registrant’s Form 10-K filed on March 9, 2005).

	10	.4	Devon Energy Corporation Restricted Stock Bonus Plan (incorporated by reference to Registrant’s Form S-8 filed on August 29, 2000, File No. 333-44702).*

	10	.5	Devon Energy Corporation 2003 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-104922, filed May 1, 2003).

	10	.6	Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-127630, filed August 17, 2005).

	10	.7	Devon Energy Corporation 1997 Stock Option Plan (as amended August 29, 2000) (incorporated by reference to Exhibit A to Registrant’s Proxy Statement for the 1997 Annual Meeting of Shareholders filed on April 3, 1997).*

	10	.8	Devon Energy Corporation 1993 Stock Option Plan (incorporated by reference to Exhibit A to Registrant’s Proxy Statement for the 1993 Annual Meeting of Shareholders filed on May 6, 1993).*.

	10	.9	Global Natural Resources Inc. 1992 Stock Option Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

130


Exhibit No.			Description

	10	.10	Mitchell Energy & Development Corp. 1999 Stock Option Plan (incorporated by reference to Exhibit 10(d) of the Annual Report on Form 10-K dated January 31, 2000).*

	10	.11	Mitchell Energy & Development Corp. 1995 Stock Option Plan (incorporated by reference to SEC File No. 333-06981).*

	10	.12	Ocean Energy, Inc. Long Term Incentive Plan for Non-Executive Employees (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.13	Ocean Energy, Inc. 1994 Long Term Incentive Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.14	Ocean Energy, Inc. 1996 Long Term Incentive Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.15	Ocean Energy, Inc. 1998 Long Term Incentive Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.16	Ocean Energy, Inc. 1999 Long Term Incentive Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.17	Ocean Energy, Inc. 2001 Long Term Incentive Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.18	PennzEnergy Company 1998 Incentive Plan (incorporated by reference to Exhibit 4.3 to Pennzoil Company’s Form S-8 filed on December 29, 1998 SEC No. 333-69845).*

	10	.19	Pennzoil Company 1998 Stock Option Plan (incorporated by reference to SEC File No. 333-59011).*

	10	.20	Pennzoil Company 1997 Incentive Plan (incorporated by reference to Exhibit A to Pennzoil Company definitive proxy material filed on March 21, 1997, SEC File No. 1-5591).*

	10	.21	Pennzoil Company 1997 Stock Option Plan (incorporated by reference to SEC File No. 333-26021).*

	10	.22	Pennzoil Company 1990 Stock Option Plan (incorporated by reference to Pennzoil Company’s definitive proxy material filed on April 26, 1990, File No. 1-5591).*

	10	.23	Santa Fe Snyder Corporation 1999 Stock Compensation Retention Plan (incorporated by reference to Exhibit 10(a) to Santa Fe Snyder Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999).*

	10	.24	Santa Fe Energy Resources Incentive Compensation Plan, as amended (incorporated by reference to Exhibit 10(a) to Santa Fe Energy Resources, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1998).*

	10	.25	Santa Fe Energy Resources, Inc. 1995 Incentive Stock Compensation Plan for Nonexecutive Officers (incorporated by reference to SEC File No. 033-59255).*

	10	.26	Santa Fe Energy Resources Deferred Compensation Plan, effective as of January 1, 1991, as amended and restated, effective February 1, 1994 (incorporated by reference to Exhibit 10(p) to Santa Fe Energy Resources, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1993).*

	10	.27	Santa Fe Energy Resources 1990 Incentive Stock Compensation Plan, Third Amendment and Restatement (incorporated by reference to Exhibit 10(a) to Santa Fe Energy Resources, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1996).*

131


Exhibit No.			Description

	10	.28	Santa Fe Energy Resources, Inc. Supplemental Retirement Plan effective as of December 4, 1990 (incorporated by reference to Exhibit 10(h) to Santa Fe Energy Resources, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1996).*

	10	.29	Seagull Energy Corporation 1990 Stock Option Plan (incorporated by reference to Registrant’s Form 10-K for the year ended December 31, 2002).

	10	.30	Seagull Energy Corporation 1993 Non-Employee Directors’ Stock Option Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.31	Seagull Energy Corporation 1993 Stock Option Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.32	United Meridian Corporation 1994 Outside Director’s Nonqualified Stock Option Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.33	United Meridian Corporation 1994 Employee Nonqualified Stock Option Plan (incorporated by reference to Registrant’s Post Effective Amendment No. 1 to Form S-4 on Form S-8 Registration No. 333-103679, filed April 28, 2003).

	10	.34	Supplemental Retirement Income Agreement among Devon Energy Corporation (Nevada), Registrant and John W. Nichols, dated March 26, 1997 (incorporated by reference to Exhibit 10.13 to Registrant’s Form 10-Q for the quarter ended June 30, 1997).*

	10	.35	Form of Employment Agreement between Registrant and Stephen J. Hadden, Brian J. Jennings, Duke R. Ligon, Marian J. Moon, J. Larry Nichols, John Richels and Darryl G. Smette, dated January 1, 2002 (incorporated by reference to Exhibit 10.26 of Registrant’s Form 10-K for the year ended December 31, 2001).*

	10	.36	Form of Award Agreement between Registrant and Stephen J. Hadden, Brian J. Jennings, Duke R. Ligon, Marian J. Moon, J. Larry Nichols, John Richels and Darryl G. Smette for stock options granted from the 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.39 to Registrant’s Form 10-Q for the quarter ended June 30, 2005).*

	10	.37	Form of Award Agreement between Registrant and all Non-Management Directors for stock options granted from the 2005 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.40 to Registrant’s Form 10-Q for the quarter ended June 30, 2005).*

	10	.38	Form of Award Agreement from the 2005 Long-Term Incentive Plan between Registrant and Stephen J. Hadden, Brian J. Jennings, Duke R. Ligon, Marian J. Moon, J. Larry Nichols, John Richels, Darryl G. Smette and all Non-Management Directors for restricted stock awards (incorporated by reference to Exhibit 10.41 to Registrant’s Form 10-Q for the quarter ended June 30, 2005).*

	12		Statement of computations of ratios of earnings to fixed charges and to combined fixed charges and preferred stock dividends.

	21		Registrant’s Significant Subsidiaries.

	23	.1	Consent of KPMG LLP.

	23	.2	Consent of LaRoche Petroleum Consultants.

	23	.3	Consent of Ryder Scott Company, L.P.

	23	.4	Consent of AJM Petroleum Consultants.

132


Exhibit No.			Description

	31	.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-15(e) and 15d-15(e), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31	.2	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to Rule 13a-15(e) and 15d-15(e), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32	.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32	.2	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*	Compensatory plans or arrangements

133

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	Devon Energy Corporation

	By: /s/ J. Larry Nichols,


	J. Larry Nichols,
	Chairman of the Board and
	Chief Executive Officer

March 1, 2006

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



/s/ J. Larry Nichols J. Larry Nichols	Chairman of the Board, Chief Executive Officer and Director	March 1, 2006

/s/ John Richels John Richels	President	March 1, 2006

/s/ Brian J. Jennings Brian J. Jennings	Senior Vice President — Corporate Finance and Development and Chief Financial Officer	March 1, 2006

/s/ Danny J. Heatly Danny J. Heatly	Vice President — Accounting and Chief Accounting Officer	March 1, 2006

/s/ Thomas F. Ferguson Thomas F. Ferguson	Director	March 1, 2006

/s/ Peter J. Fluor Peter J. Fluor	Director	March 1, 2006

/s/ David M. Gavrin David M. Gavrin	Director	March 1, 2006

/s/ John A. Hill John A. Hill	Director	March 1, 2006

/s/ Robert L. Howard Robert L. Howard	Director	March 1, 2006

/s/ William J. Johnson William J. Johnson	Director	March 1, 2006

134

135

INDEX TO EXHIBITS


Exhibit No.			Description

	3	.2	Registrant’s Bylaws.

	4	.19	First Supplemental Indenture, dated December 31, 2005 to Indenture dated as of September 28, 2001 among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor and The Bank of New York Trust Company, N.A., as Trustee, relating to the 4 ³ / 8 % Senior Notes due 2007 and the 7 ¹ / 4 % Senior Notes due 2011.

	4	.23	Third Supplemental Indenture, dated January 23, 2006 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor and Wells Fargo Bank Minnesota, National Association, as Trustee, relating to the 8.25% Senior Notes due 2018.

	4	.27	Third Supplemental Indenture, dated December 31, 2005 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor, and The Bank of New York Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes.

	12		Statement of computations of ratios of earnings to fixed charges and to combined fixed charges and preferred stock dividends.

	21		Registrant’s Significant Subsidiaries.

	23	.1	Consent of KPMG LLP.

	23	.2	Consent of LaRoche Petroleum Consultants.

	23	.3	Consent of Ryder Scott Company, L.P.

	23	.4	Consent of AJM Petroleum Consultants.

	31	.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-15(e) and 15d-15(e), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31	.2	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to Rule 13a-15(e) and 15d-15(e), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32	.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

	32	.2	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*	Compensatory plans or arrangements


		Exhibit 3.2

BYLAWS

DEVON ENERGY CORPORATION

(Adopted March 1, 2006)

ARTICLE I

OFFICES

Section 1 . Registered Office . The registered office of Devon Energy Corporation (“the Corporation”) shall be in the City of Wilmington, County of New Castle, State of Delaware.

Section 2 . Other Offices . The Corporation may also have offices at such other places both within and without the State of Delaware as the Board of Directors may from time to time determine.

ARTICLE II

MEETINGS OF STOCKHOLDERS

Section 1 . Place of Meetings . Meetings of the stockholders for the election of directors or for any other purpose shall be held at the principal office of the Corporation or at such other place, either within or without the State of Delaware as shall be designated from time to time by the Board of Directors. The Board of Directors may, in its sole discretion, determine that a meeting of stockholders shall not be held at any place, but instead may be held solely by means of remote communications.

Section 2 . Annual Meetings . The meeting of stockholders for the election of directors shall be held annually on such date as shall be designated by the Board of Directors. The Board of Directors shall designate the place and time for the holding of the meeting, and at least 10 days notice of the place and time of the meeting shall be given to the stockholders.

Section 3 . Special Meetings . Unless otherwise required by law or by the certificate of incorporation of the Corporation, as amended and restated from time to time (including any certificates of designation with respect to any Preferred Stock, the “Certificate of Incorporation”), special meetings of stockholders, for any purpose or purposes, may be called only (i) pursuant to a resolution adopted by a majority of the then-authorized number of directors of the Corporation or (ii) by the Chairman of the Board, the Chief Executive Officer or the President of the Corporation, in either case with the concurrence of a majority of the then-authorized number of directors.

Section 4 . Notice . Whenever stockholders are required or permitted to take any action at a meeting, a written notice of the meeting shall be given by the Corporation which shall state the place, if any, date and hour of the meeting, the means of remote communications, if any, by which stockholders or proxyholders may be deemed to be present and vote at such meeting and, in the case of a special meeting, the purpose or purposes for which the meeting is called. Unless otherwise required by law, the written notice of any meeting shall be given not less than 10 nor more than 60 days before the date of the meeting to each stockholder entitled to vote at such meeting.

Section 5 . Participation by Remote Communications . For any meeting of stockholders, the Board of Directors may, in its sole discretion, allow stockholders and proxyholders not physically present at a meeting of stockholders to participate by means of remote communications at such meeting and to be deemed present in person and vote at the meeting of stockholders whether the meeting is to be held at a designated place or solely by means of remote communications. For any meeting of stockholders for which the Board of Directors has authorized participation by means of remote communication, the Corporation shall (i) implement means to determine whether any person deemed present and permitted to vote at the meeting by means of remote communications is a stockholder or proxyholder, (ii) implement remote measures to provide such stockholders and proxyholders a reasonable opportunity to participate in the meeting and to vote on matters submitted to the stockholders, including an opportunity to read or hear the proceedings of the meeting substantially concurrently with such proceedings and (iii) maintain a record of any vote or other action taken by a stockholder or proxyholder at such meeting by means of remote communications.

Section 6 . Adjournments . Any meeting of the stockholders may be adjourned from time to time to reconvene at the same or some other place, and, unless otherwise required by law and subject to the provisions hereof, notice need not be given of any such adjourned meeting if the time, if any, place thereof and the means of remote communications, if any, by which stockholders or proxyholders may be deemed to be present and vote at such adjourned meeting are announced at the meeting at which the adjournment is taken. At the adjourned meeting, the Corporation may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 30 days or if after the adjournment a new record date is fixed for the adjourned meeting, notice of the adjourned meeting shall be given to each stockholder of record entitled to vote at the meeting.

Section 7 . Quorum . Unless otherwise required by law or the Certificate of Incorporation, the presence in person, by proxy or by means of remote communications if authorized by the Board of Directors as provided in Section 5 of holders of a majority of the voting power of the then-outstanding shares of Voting Stock (as defined in the Certificate of Incorporation) on the record date, shall constitute a quorum at all meetings of the stockholders for the transaction of business. A quorum, once established, shall not be broken by the withdrawal of enough votes to leave less than a quorum. If,

however, such quorum shall not be present or represented at any meeting of the stockholders, the stockholders entitled to vote thereat, present in person or represented by proxy, shall have power to adjourn the meeting from time to time, in the manner provided in Section 6, until a quorum shall be present or represented.

Section 8 . Voting . Unless otherwise required by law, the Certificate of Incorporation or these Bylaws, any question brought before any meeting of stockholders, other than the election of directors, shall be decided by the vote of the holders of a majority of the total number of votes of the capital stock represented at the meeting in person, by proxy, or by means of remote communications if authorized by the Board of Directors as provided in Section 5 and entitled to vote thereat, voting as a single class. Unless otherwise provided in the Certificate of Incorporation, and subject to Section 6 of Article V hereof, each stockholder represented at a meeting of stockholders shall be entitled to cast one vote for each share of the capital stock entitled to vote thereat held by such stockholder. Such votes may be cast in person, by proxy, or by means of remote communications if authorized by the Board of Directors as provided in Section 5, but no proxy shall be voted on or after three years from its date, unless such proxy provides for a longer period. The Board of Directors, in its discretion, or the officer of the Corporation presiding at a meeting of stockholders, in such officer’s discretion, may require that any votes cast at such meeting shall be cast by written ballot.

Section 9 . Director Nominations; Shareholder Proposals .

(A) Annual Meeting of Stockholders.

(1) Nominations of persons for election to the Board of Directors of the Corporation (except as otherwise provided in the Certificate with respect to directors to be elected by the holders of any class or series of Preferred Stock) and the proposal of business to be considered by the stockholders may be made at an annual meeting of stockholders only (a) as specified in the Corporation’s notice of meeting delivered pursuant to Article II, Section 4 of these Bylaws given by or at the direction of the Board of Directors, (b) otherwise by or at the direction of the Board of Directors or (c) by any stockholder of the Corporation who is entitled to vote at the meeting, who has complied with the notice procedures set forth in subparagraphs (2) and (3) of this paragraph (A) of this Bylaw and who was a stockholder of record at the time such notice is delivered to the Secretary of the Corporation and on the record date for the determination of stockholders certified to vote at such meetings.

(2) For nominations or other business to be properly brought before an annual meeting by a stockholder pursuant to clause (c) of paragraph (A)(1) of this Bylaw, the stockholder must have given timely notice thereof in writing to the Secretary of the Corporation, and in the case of business other than nominations, such other business must be a proper matter for stockholder action. To be timely, a stockholder’s notice shall be delivered to, and received by, the Secretary at the principal

executive offices of the Corporation not less than 90 days nor more than 120 days prior to the first anniversary of the preceding year’s annual meeting; provided, however, that in the event that the date of the annual meeting is not within 30 days before or after such anniversary date, notice by the stockholder to be timely must be so delivered not earlier than the 90 ^th day prior to such annual meeting and not later than the close of business on the later of the 70 ^th day prior to such annual meeting or the 10 ^th day following the day on which public announcement of the date of such meeting is first made. Such stockholder’s notice shall set forth (a) as to each person whom the stockholder proposes to nominate for election or reelection as a director, all information relating to such person that is required to be disclosed in solicitations of proxies for election of directors, or is otherwise required, in each case pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including such person’s written consent to being named in the proxy statement as a nominee and to serving as a director if elected; (b) as to any other business that the stockholder proposes to bring before the meeting, a brief description of the business desired to be brought before the meeting (which, if the proposal is for any alteration, amendment, rescission or repeal of these Bylaws, shall include the text of the resolution which will be proposed to implement the same, and which business shall, in any case, be a proper subject to be brought before such meeting), the reasons for conducting such business at the meeting and any material interest in such business of such stockholder and the beneficial owner, if any, on whose behalf the proposal is made; and (c) as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made (i) the name and address of such stockholder, as they appear on the Corporation’s books, and of such beneficial owner, (ii) the class and number of shares of the Corporation which are owned beneficially and of record by such stockholder and such beneficial owner, (iii) a description of all arrangements or understandings between such stockholder and any other person or persons (including their names) in connection with the proposal of such business by such stockholder and (iv) a representation that such stockholder intends to appear in person or by proxy at the annual meeting to bring such business before the meeting.

(3) Notwithstanding anything in the second sentence of paragraph (A)(2) of this Bylaw to the contrary, in the event that the number of directors to be elected to the Board of Directors of the Corporation is increased and there is no public announcement naming all of the nominees for director or specifying the size of the increased Board of Directors made by the Corporation at least 80 days prior to the first anniversary of the preceding year’s annual meeting, a stockholder’s notice required by this Bylaw shall also be considered timely, but only with respect to nominees for any new positions created by such increase, if it shall be delivered to, and received by, the Secretary at the principal executive offices of the Corporation not later than the close of business on the 10 ^th day following the day on which such public announcement is first made by the Corporation.

(B) Special Meetings of Stockholders. Only such business shall be conducted at a special meeting of stockholders as shall have been brought before the meeting pursuant to the Corporation’s notice of meeting pursuant to Article II, Section 4 of these Bylaws given by or at the direction of the Board of Directors. Nominations of persons for election to the Board of Directors may be made at a special meeting of stockholders at which the Corporation’s notice of meeting specifies that directors are to be elected (a) by or at the direction of the Board of Directors or (b) by any stockholder of the Corporation who is entitled to vote at the meeting, who complies with the notice procedures set forth in this Bylaw and who is a stockholder of record at the time such notice is delivered to the Secretary of the Corporation and on the record date for the determination of stockholders entitled to vote at such meetings. Nominations of stockholders of persons for election to the Board of Directors at such a special meeting of stockholders may be made only if the stockholder’s notice, as required by paragraph (A)(2) of this Bylaw, shall be delivered to, and received by, the Secretary at the principal executive offices of the Corporation not later than the close of business on the 10 ^th day following the day on which public announcement is first made of the date of the special meeting.

(C) General.

(1) Only persons who are nominated in accordance with the procedures set forth in this Bylaw shall be eligible to serve as directors, and only such business shall be conducted at a meeting of stockholders as shall have been brought before the meeting in accordance with the procedures set forth in this Bylaw and shall otherwise constitute a proper subject to be brought before the meeting. Except as otherwise provided by law, the Certificate of Incorporation or these Bylaws, the presiding officer of the meeting shall have the power and duty to determine whether a nomination or any business proposed to be brought before the meeting was made in accordance with the procedures set forth in this Bylaw and, if any proposed nomination or business is not in compliance with this Bylaw, to declare that such defective nomination shall be disregarded or that such proposed business shall not be transacted.

(2) For purposes of this Bylaw, “public announcement” shall mean disclosure in a press release reported by the Dow Jones News Service, Associated Press or comparable national news service or in a document publicly filed by the Corporation with the Securities and Exchange Commission pursuant to Section 13, 14 or 15(d) of the Exchange Act.

(3) For purposes of this Bylaw, no adjournment nor notice of adjournment of any meeting shall be deemed to constitute a new notice of such meeting for purposes of this Section 9, and in order for any notification required to be delivered by a stockholder pursuant to this Section 9 to be timely, such notification must be delivered within the periods set forth above with respect to the originally scheduled meeting.

(4) Notwithstanding the foregoing provisions of this Bylaw, a stockholder shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Bylaw. Nothing in this Bylaw shall be deemed to affect any rights of stockholders to request inclusion of proposals in the Corporation’s proxy statement pursuant to Rule 14a-8 under the Exchange Act or to require inclusion of nominations or proposals of stockholders which the Corporation is not otherwise required to include in its proxy statement.

Section 10 . List of Stockholders Entitled to Vote . The officer of the Corporation who has charge of the stock ledger of the Corporation shall prepare and make, at least 10 days before every meeting of stockholders, a complete list of the stockholders entitled to vote at the meeting, arranged in alphabetical order and showing the address of each stockholder and the number of shares registered in the name of each stockholder. Such list shall be open to the examination of any stockholder, for any purpose germane to the meeting, during ordinary business hours, for a period of at least 10 days prior to the meeting either at a place within the city where the meeting is to be held, which place shall be specified in the notice of the meeting, or, if not so specified, at the place where the meeting is to be held. The list shall also be produced and kept at the time and place of the meeting during the whole time thereof and may be inspected by any stockholder of the Corporation who is present.

Section 11 . Stock Ledger . The stock ledger of the Corporation shall be the only evidence as to who are the stockholders entitled to examine the stock ledger, the list required by Section 10 of this Article II or the books of the Corporation, or to vote in person or by proxy at any meeting of stockholders.

Section 12 . Conduct of Meetings . The Board of Directors of the Corporation may adopt by resolution such rules and regulations for the conduct of the meeting of the stockholders as it shall deem appropriate. Except to the extent inconsistent with such rules and regulations as adopted by the Board of Directors, the presiding officer of any meeting of the stockholders shall have the right and authority to prescribe such rules, regulations and procedures and to do all such acts as, in the judgment of such presiding officer, are appropriate for the proper conduct of the meeting. Such rules, regulations or procedures, whether adopted by the Board of Directors or prescribed by the presiding officer of the meeting, may include, without limitation, the following: (i) the establishment of an agenda or order of business for the meeting; (ii) the determination of when the polls shall open and close for any given matter to be voted on at the meeting; (iii) rules and procedures for maintaining order at the meeting and the safety of those present; (iv) limitations on attendance at or participation in the meeting to stockholders of record of the corporation, their duly authorized and constituted proxies or such other persons as the presiding officer of the meeting shall determine; (v) restrictions on entry to the meeting after the time fixed for the commencement thereof; and (vi) limitations on the time allotted to questions or comments by participants.

Section 13 . Inspectors of Election . The Corporation shall, in advance of any meeting of stockholders, appoint one or more inspectors of election, who may be employees of the Corporation, to act at the meeting or any adjournment thereof and to make a written report thereof. The Corporation may designate one or more persons as alternate inspectors to replace any inspector who fails to act. In the event that no inspector so appointed or designated is able to act at a meeting of stockholders, the person presiding at the meeting shall appoint one or more inspectors to act at the meeting. Each inspector, before entering upon the discharge of his or her duties, shall take and sign an oath to execute faithfully the duties of inspector with strict impartiality and according to the best of his or her ability.

The inspector or inspectors so appointed or designated shall (i) ascertain the number of shares of capital stock of the Corporation outstanding and the voting power of each such share, (ii) determine the shares of capital stock of the Corporation represented at the meeting and the validity of proxies and ballots, (iii) count all votes and ballots including ballots cast by electronic transmission if participation at the meeting by means of remote communications is authorized by the Board of Directors as provided in Section 5, (iv) determine and retain for a reasonable period a record of the disposition of any challenges made to any determination by the inspectors, and (v) certify their determination of the number of shares of capital stock of the Corporation represented at the meeting and such inspectors’ count of all vote and ballots. Such certification and report shall specify such other information as may be required by law. In determining the validity and counting of proxies and ballots cast at any meeting of stockholders of the Corporation, the inspectors may consider such information as is permitted by applicable law. No person who is a candidate for an office at an election may serve as an inspector at such election.

ARTICLE III

DIRECTORS

Section 1 . Number and Election of Directors . Subject to the Certificate of Incorporation, the Board of Directors shall consist of not less than three nor more than 20 members, the exact number of which shall be fixed from time to time by the Board of Directors. Subject to the Certificate of Incorporation and except as provided in Section 2 of this Article III, directors shall be elected by a plurality of the votes cast at the annual meetings of stockholders. The directors shall be divided into three classes in the manner set forth in the Certificate of Incorporation, each class to be elected for the term set forth therein or as provided in the Delaware General Corporation Law. Each director shall serve until his or her successor is duly elected and qualified or until such director’s earlier death, resignation or removal. Any director may resign at any time upon written notice to the Corporation. Directors need not be stockholders.

Section 2 . Vacancies . Unless otherwise required by law or the Certificate of Incorporation, vacancies arising through death, resignation, removal, an increase in the number of directors or otherwise may be filled only by a majority of the directors then in office, though less than a quorum, or by a sole remaining director, and the directors so chosen shall hold office for the remainder of the full term of the class of directors in which the new directorship was created or in which the vacancy occurred and until their successors are duly elected and qualified or until their earlier death, resignation or removal.

Section 3 . Duties and Powers . The business and affairs of the Corporation shall be managed by or under the direction of the Board of Directors which may exercise all such powers of the Corporation and do all such lawful acts and things as are not by statute or by the Certificate of Incorporation or by these Bylaws required to be exercised or done by the stockholders.

Section 4 . Meetings . The Board of Directors may hold meetings, both regular and special, either within or without the State of Delaware. Regular meetings of the Board of Directors may be held without notice at such time and at such place as may from time to time be determined by the Board of Directors. Special meetings of the Board of Directors may be called by the Chairman of the Board, the Chief Executive Officer or by the President and shall be called upon the written request of a majority of the directors. Notice thereof stating the place, date and hour of the meeting shall be given to each director either by mail not less than forty-eight (48) hours before the date of the meeting, by telephone or telegram on twenty-four (24) hours notice or on such shorter notice as the person or persons calling such meeting may deem necessary or appropriate in the circumstances.

Section 5 . Quorum . Except as otherwise required by law or the Certificate of Incorporation, at all meetings of the Board of Directors, a majority of the entire Board of Directors shall constitute a quorum for the transaction of business, and the act of a majority of the directors present at any meeting at which there is a quorum shall be the act of the Board of Directors. If a quorum shall not be present at any meeting of the Board of Directors, the directors present thereat may adjourn the meeting from time to time, without notice other than announcement at the meeting of the time and place of the adjourned meeting, until a quorum shall be present.

Section 6 . Actions by Written Consent . Unless otherwise provided in the Certificate of Incorporation or these Bylaws, any action required or permitted to be taken at any meeting of the Board of Directors or of any committee thereof may be taken without a meeting, if all the members of the Board of Directors or committee, as the case may be, consent thereto in writing or by electronic transmission and the writing or writings or electronic transmission or transmissions are filed with the minutes of proceedings of the Board of Directors or committee.

Section 7 . Meetings by Means of Conference Telephone . Unless otherwise provided in the Certificate of Incorporation, members of the Board of Directors of the Corporation, or any committee thereof, may participate in a meeting of the Board of Directors or such committee by means of a conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in a meeting pursuant to this Section 7 shall constitute presence in person at such meeting.

Section 8 . Committees . The Board of Directors may designate one or more committees, each committee to consist of one or more of the directors of the Corporation. The Board of Directors may designate one or more directors as alternate members of any committee, who may replace any absent or disqualified member at any meeting of any such committee. Any committee, to the extent permitted by law and provided in the resolution establishing such committee, shall have and may exercise all the powers and authority of the Board of Directors in the management of the business and affairs of the Corporation and may authorize the seal of the Corporation to be affixed to all papers which may require it. Each committee shall keep regular minutes and report to the Board of Directors when required. Except as otherwise required by law or the Certificate of Incorporation, at all meetings of committees of the Board of Directors, a majority of the entire committee shall constitute a quorum for the transaction of business, and the act of a majority of the members of the committee present at any meeting at which there is a quorum shall be the act of the committee. If a quorum shall not be present at any meeting of a committee of the Board of Directors, the members of the committee present thereat may adjourn the meeting from time to time, without notice other than announcement at the meeting of the time and place of the adjourned meeting, until a quorum shall be present.

Section 9 . Compensation . The directors may be paid their expenses, if any, of attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors or a stated salary as director, payable in cash or securities. No such payment shall preclude any director from serving the Corporation in any other capacity and receiving compensation therefor. Members of special or standing committees may be allowed like compensation for attending committee meetings.

Section 10 . Interested Directors . No contract or transaction between the Corporation and one or more of its directors or officers, or between the Corporation and any other corporation, partnership, association or other organization in which one or more of its directors or officers are directors or officers or have a financial interest, shall be void or voidable solely for this reason, solely because the director or officer is present at or participates in the meeting of the Board of Directors or committee thereof which authorizes the contract or transaction or solely because the director or officer’s vote is counted for such purpose if (i) the material facts as to the director or officer’s relationship or interest and as to the contract or transaction are disclosed or are known to the Board of Directors or the committee, and the Board of Directors or committee, in

good faith, authorizes the contract or transaction by the affirmative votes of a majority of the disinterested directors, even though the disinterested directors be less than a quorum; (ii) the material facts as to the director or officer’s relationship or interest and as to the contract or transaction are disclosed or are known to the stockholders entitled to vote thereon, and the contract or transaction is specifically approved in good faith by vote of the stockholders; or (iii) the contract or transaction is fair as to the Corporation as of the time it is authorized, approved or ratified by the Board of Directors, a committee thereof or the stockholders. Common or interested directors may be counted in determining the presence of a quorum at a meeting of the Board of Directors or of a committee which authorizes the contract or transaction.

ARTICLE IV

OFFICERS

Section 1 . General . The officers of the Corporation shall be chosen by the Board of Directors and shall be a Chairman of the Board (who must be a director), one or more Vice Chairmen (who must be directors), a Chief Executive Officer, a President, a Secretary and a Treasurer. The Board of Directors, in its discretion, also may choose one or more Vice Presidents, Assistant Secretaries, Assistant Treasurers and other officers. Any number of offices may be held by the same person, unless otherwise prohibited by law or the Certificate of Incorporation. The officers of the Corporation need not be stockholders of the Corporation nor, except in the case of the Chairman of the Board of Directors or the Vice Chairmen, need such officers be directors of the Corporation.

Section 2 . Election . The Board of Directors, at its first meeting held after each annual meeting of stockholders, shall elect the officers of the Corporation who shall hold their offices for such terms and shall exercise such powers and perform such duties as shall be determined from time to time by the Board of Directors; and all officers of the Corporation shall hold office until their successors are chosen and qualified or until their earlier death, resignation or removal. Any officer elected by the Board of Directors may be removed at any time by the affirmative vote of directors constituting two-thirds or more of the Board of Directors. Any vacancy occurring in any office of the Corporation shall be filled by the Board of Directors.

Section 3 . Voting Securities Owned by the Corporation . Powers of attorney, proxies, waivers of notice of meeting, consents and other instruments relating to securities owned by the Corporation may be executed in the name of and on behalf of the Corporation by the Chairman of the Board, the Chief Executive Officer, the President or any Vice President or any other officer authorized to do so by the Board of Directors, and any such officer may, in the name of and on behalf of the Corporation, take all such action as any such officer may deem advisable to vote in person or by proxy at any meeting of security holders of any corporation in which the Corporation may own securities and at any such meeting shall possess and may exercise any and

all rights and power incident to the ownership of such securities and which, as the owner thereof, the Corporation might have exercised and possessed if present. The Board of Directors may, by resolution, from time to time, confer like powers upon any other person or persons.

Section 4 . Chairman of the Board of Directors . The Chairman of the Board of Directors shall preside at all meetings of the Board of Directors and at all meetings of the stockholders. The Chairman of the Board shall be the Chairman of the Executive Committee if established pursuant to Article IX of the Certificate of Incorporation and shall preside at all meetings thereof. The Chairman of the Board shall have such other powers and duties as shall be assigned to him by these Bylaws or by the Board of Directors.

Section 5 . Vice Chairmen of the Board of Directors . Vice Chairmen of the Board of Directors shall have such powers and duties as shall be assigned to them by the Board of Directors.

Section 6 . Chief Executive Officer . The Chief Executive Officer shall have general and active management of the business of the Corporation, and shall see that all orders and resolutions of the Board of Directors and of the committees thereof are carried into effect. The Chief Executive Officer shall have authority, which he may delegate, to execute certificates of stock, bonds, deeds, powers of attorney, mortgages and other contracts, under the seal of the Corporation, unless required by law to be otherwise signed and executed and unless the signing and execution thereof shall be expressly and exclusively delegated by the Board of Directors to some other officer or agent of the Corporation.

Section 7 . President . The President shall, subject to the control of the Board of Directors and the Chief Executive Officer, have general supervision of the business of the Corporation and shall see that all orders and resolutions of the Board of Directors are carried into effect. The President shall execute all bonds, mortgages, contracts and other instruments of the Corporation requiring a seal, under the seal of the Corporation, except where required or permitted by law to be otherwise signed and executed and except that the other officers of the Corporation may sign and execute documents when so authorized by these Bylaws, the Board of Directors, the Chief Executive Officer or the President. In the absence or disability of the Chairman of the Board or the Chief Executive Officer, the President shall preside at meetings of stockholders or of the Board of Directors. The President shall also perform such other duties and may exercise such other powers as may from time to time be assigned to such officer by these Bylaws or by the Board of Directors or the Chief Executive Officer.

Section 8 . Vice Presidents . At the request of the President or in the President’s absence or in the event of the President’s inability or refusal to act, the Vice President, or the Vice Presidents if there is more than one (in the order designated by the Board of Directors or the Chief Executive Officer) shall perform the duties of the President and,

when so acting, shall have all the powers of and be subject to all the restrictions upon the President. Each Vice President shall perform such other duties and have such other powers as the Board of Directors from time to time may prescribe. If there be no Vice President, the Board of Directors shall designate the officer of the Corporation who, in the absence of the President or in the event of the inability or refusal of the President to act, shall perform the duties of the President and, when so acting, shall have all the powers of and be subject to all the restrictions upon the President.

Section 9 . Secretary . The Secretary shall attend all meetings of the Board of Directors and all meetings of stockholders and record all the proceedings thereat in a book or books to be kept for that purpose; the Secretary shall also perform like duties for committees of the Board of Directors when required. The Secretary shall give, or cause to be given, notice of all meetings of the stockholders and special meetings of the Board of Directors and shall perform such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Chief Executive Officer or the President. If the Secretary shall be unable or shall refuse to cause to be given notice of all meetings of the stockholders and special meetings of the Board of Directors, then either the Board of Directors, the Chairman of the Board, the Chief Executive Officer or the President may choose another officer to cause such notice to be given. The Secretary shall have custody of the seal of the Corporation and the Secretary or any Assistant Secretary, if there be one, shall have authority to affix the same to any instrument requiring it, and when so affixed, it may be attested by the signature of the Secretary or by the signature of any such Assistant Secretary. The Board of Directors may give general authority to any other officer to affix the seal of the Corporation and to attest to the affixing by such officer’s signature. The Secretary shall see that all books, reports, statements, certificates and other documents and records required by law to be kept or filed are properly kept or filed, as the case may be.

Section 10 . Treasurer . The Treasurer shall have the custody of the corporate funds and cash equivalents and shall keep full and accurate accounts of receipts and disbursements in books belonging to the Corporation and shall deposit all moneys and other valuable effects in the name and to the credit of the Corporation in such depositories as may be designated by the Board of Directors. The Treasurer shall disburse the funds of the Corporation as may be ordered by the Board of Directors, taking proper vouchers for such disbursements, and shall render to the Chief Executive Officer, President and the Board of Directors, at its regular meetings, or when the Board of Directors so requires, an account of all transactions as Treasurer and of the financial condition of the Corporation. If required by the Board of Directors, the Treasurer shall give the Corporation a bond in such sum and with such surety or sureties as shall be satisfactory to the Board of Directors for the faithful performance of the duties of the office of the Treasurer and for the restoration to the Corporation, in case of the Treasurer’s death, resignation, retirement or removal from office, of all books, papers, vouchers, money and other property of whatever kind in the Treasurer’s possession or under the Treasurer’s control belonging to the Corporation.

Section 11 . Assistant Secretaries . Assistant Secretaries, if there be any, shall perform such duties and have such powers as from time to time may be assigned to them by the Board of Directors, the Chairman of the Board, the Chief Executive Officer, the President, any Vice President, if there be one, or the Secretary, and in the absence of the Secretary or in the event of the Secretary’s disability or refusal to act, shall perform the duties of the Secretary and, when so acting, shall have all the powers of and be subject to all the restrictions upon the Secretary.

Section 12 . Assistant Treasurers . Assistant Treasurers, if there be any, shall perform such duties and have such powers as from time to time may be assigned to them by the Board of Directors, the Chief Executive Officer, the President, any Vice President, if there be one, or the Treasurer, and in the absence of the Treasurer or in the event of the Treasurer’s disability or refusal to act, shall perform the duties of the Treasurer and, when so acting, shall have all the powers of and be subject to all the restrictions upon the Treasurer. If required by the Board of Directors, an Assistant Treasurer shall give the Corporation a bond in such sum and with such surety or sureties as shall be satisfactory to the Board of Directors for the faithful performance of the duties of the office of Assistant Treasurer and for the restoration to the Corporation, in case of the Assistant Treasurer’s death, resignation, retirement or removal from office, of all books, papers, vouchers, money and other property of whatever kind in the Assistant Treasurer’s possession or under the Assistant Treasurer’s control belonging to the Corporation.

Section 13 . Other Officers . Such other officers as the Board of Directors may choose shall perform such duties and have such powers as from time to time may be assigned to them by the Board of Directors. The Board of Directors may delegate to any other officer of the Corporation the power to choose such other officers and to prescribe their respective duties and powers.

ARTICLE V

STOCK

Section 1 . Form of Certificates . The shares of stock of the Corporation shall be represented by certificates, provided that the Board of Directors may provide by resolution or resolutions that some or all of any or all classes or series of the Corporation’s stock shall be uncertificated shares. Any such resolution shall not apply to shares represented by a certificate until such certificate is surrendered to the Corporation. Notwithstanding the adoption of such a resolution by the Board of Directors, every holder of stock represented by certificates and, upon request, every holder of uncertificated shares shall be entitled to have a certificate signed, in the name of the Corporation (i) by the Chief Executive Officer, the President or a Vice President and (ii) by the Treasurer or an Assistant Treasurer, or the Secretary or an Assistant Secretary of the Corporation, certifying the number of shares owned by such stockholder in the Corporation.

Section 2 . Signatures . Any or all of the signatures on a certificate may be a facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, transfer agent or registrar before such certificate is issued, such certificate may be issued by the Corporation with the same effect as if such person were such officer, transfer agent or registrar at the date of issue.

Section 3 . Lost Certificates . The Board of Directors may direct a new certificate to be issued in place of any certificate theretofore issued by the Corporation alleged to have been lost, stolen or destroyed, upon the making of an affidavit of that fact by the person claiming the certificate of stock to be lost, stolen or destroyed. When authorizing such issue of a new certificate, the Board of Directors may, in its discretion and as a condition precedent to the issuance thereof, require the owner of such lost, stolen or destroyed certificate, or the owner’s legal representative, to advertise the same in such manner as the Board of Directors shall require and/or to give the Corporation a bond in such sum as it may direct as indemnity against any claim that may be made against the Corporation with respect to the certificate alleged to have been lost, stolen or destroyed or the issuance of such new certificate.

Section 4 . Transfers . Stock of the Corporation shall be transferable in the manner prescribed by law and in these Bylaws. Transfers of stock shall be made on the books of the Corporation only by the person named in the certificate or by such person’s attorney lawfully constituted in writing and upon the surrender of the certificate therefor, which shall be canceled before a new certificate shall be issued. No transfer of stock shall be valid as against the Corporation for any purpose until it shall have been entered in the stock records of the Corporation by an entry showing from and to whom transferred.

Section 5 . Record Date .

(A) In order that the Corporation may determine the stockholders entitled to notice of or to vote at any meeting of stockholders or any adjournment thereof, the Board of Directors may fix a record date, which record date shall not precede the date upon which the resolution fixing the record date is adopted by the Board of Directors and which record date shall not be more than 60 nor less than 10 days before the date of such meeting. If no record date is fixed by the Board of Directors, the record date for determining stockholders entitled to notice of or to vote at a meeting of stockholders shall be at the close of business on the day next preceding the day on which notice is given or, if notice is waived, at the close of business on the day next preceding the day on which the meeting is held. A determination of stockholders of record entitled to notice of or to vote at a meeting of stockholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for the adjourned meeting.

(B) In order that the Corporation may determine the stockholders entitled to receive payment of any dividend or other distribution or allotment of any rights or the stockholders entitled to exercise any rights in respect of any change, conversion or exchange of stock, or for the purpose of any other lawful action, the Board of Directors may fix a record date, which record date shall not precede the date upon which the resolution fixing the record date is adopted and which record date shall be not more than 60 days prior to such action. If no record date is fixed, the record date for determining stockholders for any such purpose shall be at the close of business on the day on which the Board of Directors adopts the resolution relating thereto.

Section 6 . Record Owners . The Corporation shall be entitled to recognize the exclusive right of a person registered on its books as the owner of shares to receive dividends, to vote as such owner and to hold liable for calls and assessments a person registered on its books as the owner of shares, and the Corporation shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as otherwise required by law.

ARTICLE VI

NOTICES

Section 1 . Notices . Whenever written notice is required, by law, the Certificate of Incorporation or these Bylaws, to be given to any director, member of a committee or stockholder, such notice may be given by mail, addressed to such director, member of a committee or stockholder, at such person’s address as it appears on the records of the Corporation, with postage thereon prepaid, and such notice shall be deemed to be given at the time when the same shall be deposited in the United States mail. Written notice may also be given personally or by telegram, telex, cable, or courier service (with proof of delivery).

Section 2 . Notice by Electronic Transmission . Any notice to stockholders given by the Corporation shall be effective if given by a form of electronic transmission consented to by the stockholder to whom the notice is given.

Section 3 . Waivers of Notice . Whenever any notice is required, by law, the Certificate of Incorporation or these Bylaws, to be given to any director, member of a committee or stockholder, a waiver thereof in writing, signed by the person or persons entitled to said notice, or a waiver by electronic transmission by the person or persons entitled to said notice, whether before or after the time stated therein, shall be deemed equivalent thereto. Attendance of a person at a meeting, present in person or represented by proxy, shall constitute a waiver of notice of such meeting, except where the person attends the meeting for the express purpose of objecting at the beginning of the meeting to the transaction of any business because the meeting is not lawfully called or convened.

ARTICLE VII

GENERAL PROVISIONS

Section 1 . Dividends . Dividends upon the capital stock of the Corporation, subject to the requirements of the Delaware General Corporation Law and the provisions of the Certificate of Incorporation, if any, may be declared by the Board of Directors at any regular or special meeting of the Board of Directors (or any action by written consent in lieu thereof in accordance with Section 6 of Article III hereof) and may be paid in cash, in property or in shares of the Corporation’s capital stock. Before payment of any dividend, there may be set aside out of any funds of the Corporation available for dividends such sum or sums as the Board of Directors from time to time, in its absolute discretion, deems proper as a reserve or reserves to meet contingencies, or for equalizing dividends, or for repairing or maintaining any property of the Corporation, or for any proper purpose, and the Board of Directors may modify or abolish any such reserve.

Section 2 . Disbursements . All checks or demands for money and notes of the Corporation shall be signed by such officer or officers or such other person or persons as the Board of Directors may from time to time designate.

Section 3 . Fiscal Year . The fiscal year of the Corporation shall be fixed by resolution of the Board of Directors.

Section 4 . Corporate Seal . The corporate seal shall have inscribed thereon the name of the Corporation and the words “Corporate Seal, Delaware.” The seal may be used by causing it or a facsimile thereof to be impressed, affixed or reproduced or otherwise.

ARTICLE VIII

INDEMNIFICATION

Section 1 . Power to Indemnify in Actions, Suits or Proceedings other than Those by or in the Right of the Corporation . Subject to Section 3 of this Article VIII, the Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the Corporation) by reason of the fact that such person is or was a director or officer of the Corporation, or is or was a director or officer of the Corporation serving at the request of the Corporation as a director or officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such

action, suit or proceeding if such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe such person’s conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent shall not, of itself, create a presumption that the person did not act in good faith and in a manner which such person reasonably believed to be in or not opposed to the best interests of the Corporation and, with respect to any criminal action or proceeding, had reasonable cause to believe that such person’s conduct was unlawful.

Section 2 . Power to Indemnify in Actions, Suits or Proceedings by or in the Right of the Corporation . Subject to Section 3 of this Article VIII, the Corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the Corporation to procure a judgment in its favor by reason of the fact that such person is or was a director or officer of the Corporation, or is or was a director or officer of the Corporation serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust employee benefit plan or other enterprise against expenses (including attorneys’ fees) actually and reasonably incurred by such person in connection with the defense or settlement of such action or suit if such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Corporation; except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the Corporation unless and only to the extent that the Court of Chancery or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Court of Chancery or such other court shall deem proper.

Section 3 . Authorization of Indemnification . Any indemnification under this Article VIII (unless ordered by a court) shall be made by the Corporation only as authorized in the specific case upon a determination that indemnification of the director or officer is proper in the circumstances because such person has met the applicable standard of conduct set forth in Section 1 or Section 2 of this Article VIII, as the case may be. Such determination shall be made, with respect to a person who is a director or officer at the time of such determination, (i) by a majority vote of the directors who are not parties to such action, suit or proceeding, even though less than a quorum, (ii) by a committee of such directors designated by a majority vote of such directors, even though less than a quorum, (iii) if there are no such directors, or if such directors so direct, by independent legal counsel in a written opinion or (iv) by the stockholders. Such determination shall be made, with respect to former directors and officers, by any person or persons having the authority to act on the matter on behalf of the Corporation. To the extent, however, that a present or former director or officer of the Corporation has been successful on the merits or otherwise in defense of any action, suit or

proceeding described above, or in defense of any claim, issue or matter therein, such person shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred by such person in connection therewith, without the necessity of authorization in the specific case.

Section 4 . Good Faith Defined . For purposes of any determination under Section 3 of this Article VIII, a person shall be deemed to have acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the Corporation or, with respect to any criminal action or proceeding, to have had no reasonable cause to believe such person’s conduct was unlawful, if such person’s action is based on the records or books of account of the Corporation or another enterprise, or on information supplied to such person by the officers of the Corporation or another enterprise in the course of their duties, or on the advice of legal counsel for the Corporation or another enterprise or on information or records given or reports made to the Corporation or another enterprise by an independent certified public accountant or by an appraiser or other expert selected with reasonable care by the Corporation or another enterprise. The term “another enterprise” as used in this Section 4 shall mean any other corporation or any partnership, joint venture, trust, employee benefit plan or other enterprise of which such person is or was serving at the request of the Corporation as a director, officer, employee or agent. The provisions of this Section 4 shall not be deemed to be exclusive or to limit in any way the circumstances in which a person may be deemed to have met the applicable standard of conduct set forth in Section 1 or 2 of this Article VIII, as the case may be.

Section 5 . Indemnification by a Court . Notwithstanding any contrary determination in the specific case under Section 3 of this Article VIII and notwithstanding the absence of any determination thereunder, any director or officer may apply to the Court of Chancery in the State of Delaware for indemnification to the extent otherwise permissible under Sections 1 and 2 of this Article VIII. The basis of such indemnification by a court shall be a determination by such court that indemnification of the director or officer is proper in the circumstances because such person has met the applicable standards of conduct set forth in Section 1 or 2 of this Article VIII, as the case may be. Neither a contrary determination in the specific case under Section 3 of this Article VIII nor the absence of any determination thereunder shall be a defense to such application or create a presumption that the director or officer seeking indemnification has not met any applicable standard of conduct. Notice of any application for indemnification pursuant to this Section 5 shall be given to the Corporation promptly upon the filing of such application. If successful, in whole or in part, the director or officer seeking indemnification shall also be entitled to be paid the expense of prosecuting such application.

Section 6 . Expenses Payable in Advance . Expenses incurred by a director or officer in defending any civil, criminal, administrative or investigative action, suit or proceeding shall be paid by the Corporation in advance of the final disposition of such action, suit or proceeding upon receipt of an undertaking by or on behalf of such director

or officer to repay such amount if it shall ultimately be determined that such person is not entitled to be indemnified by the Corporation as authorized in this Article VIII.

Section 7 . Nonexclusivity of Indemnification and Advancement of Expenses . The indemnification and advancement of expenses provided by or granted pursuant to this Article VIII shall not be deemed exclusive of any other rights to which those seeking indemnification or advancement of expenses may be entitled under the Certificate of Incorporation, any Bylaw, agreement, vote of stockholders or disinterested directors or otherwise, both as to action in such person’s official capacity and as to action in another capacity while holding such office, it being the policy of the Corporation that indemnification of the persons specified in Sections 1 and 2 of this Article VIII shall be made to the fullest extent permitted by law. The provisions of this Article VIII shall not be deemed to preclude the indemnification of any person who is not specified in Section 1 or 2 of this Article VIII, but whom the Corporation has the power or obligation to indemnify under the provisions of the General Corporation Law of the State of Delaware, or otherwise.

Section 8 . Insurance . The Corporation may purchase and maintain insurance on behalf of any person who is or was a director or officer of the Corporation, or is or was a director or officer of the Corporation serving at the request of the Corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise against any liability asserted against such person and incurred by such person in any such capacity, or arising out of such person’s status as such, whether or not the Corporation would have the power or the obligation to indemnify such person against such liability under the provisions of this Article VIII.

Section 9 . Certain Definitions . For purposes of this Article VIII, references to “the Corporation” shall include, in addition to the resulting corporation, any constituent corporation (including any constituent of a constituent) absorbed in a consolidation or merger which, if its separate existence had continued, would have had power and authority to indemnify its directors or officers, so that any person who is or was a director or officer of such constituent corporation, or is or was a director or officer of such constituent corporation serving at the request of such constituent corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, shall stand in the same position under the provisions of this Article VIII with respect to the resulting or surviving corporation as such person would have with respect to such constituent corporation if its separate existence had continued. For purposes of this Article VIII, references to “fines” shall include any excise taxes assessed on a person with respect to an employee benefit plan; and references to “serving at the request of the Corporation” shall include any service as a director, officer, employee or agent of the Corporation which imposes duties on, or involves services by, such director or officer with respect to an employee benefit plan, its participants or beneficiaries; and a person who acted in good faith and in a manner such person reasonably believed to be in the interest of the participants

and beneficiaries of an employee benefit plan shall be deemed to have acted in a manner “not opposed to the best interests of the Corporation” as referred to in this Article VIII.

Section 10 . Survival of Indemnification and Advancement of Expenses . The indemnification and advancement of expenses provided by, or granted pursuant to, this Article VIII shall, unless otherwise provided when authorized or ratified, continue as to a person who has ceased to be a director or officer and shall inure to the benefit of the heirs, executors and administrators of such a person.

Section 11 . Limitation on Indemnification . Notwithstanding anything contained in this Article VIII to the contrary, except for proceedings to enforce rights to indemnification (which shall be governed by Section 5 hereof), the Corporation shall not be obligated to indemnify any director or officer in connection with a proceeding (or part thereof) initiated by such person unless such proceeding (or part thereof) was authorized or consented to by the Board of Directors of the Corporation.

Section 12 . Indemnification of Employees and Agents . The Corporation may, to the extent authorized from time to time by the Board of Directors, provide rights to indemnification and to the advancement of expenses to employees and agents of the Corporation similar to those conferred in this Article VIII to directors and officers of the Corporation.

Section 13 . Contractual Rights. Without the necessity of entering into an express contract, the rights conferred upon directors and officers under this Article VIII with respect to indemnification and the advancement of expenses shall be deemed to be contractual rights upon which the directors and officers are presumed to have relied in determining to serve or to continue to serve in their capacity with the Corporation. The rights provided in this Article VIII shall be effective and legally enforceable to the same extent and as if provided for in a contract between the Corporation and each director or officer. Any amendment to or repeal of this Article VIII shall not adversely affect the rights of indemnification provided in this Article VIII with respect to any acts or omissions of a director or officer occurring prior to such amendment or repeal.

ARTICLE IX

AMENDMENTS

Section 1 . Amendments . These Bylaws may be altered, amended or repealed, in whole or in part, or new Bylaws may be adopted by the stockholders or by the Board of Directors; provided, however, that notice of such alteration, amendment, repeal or adoption of new Bylaws be contained in the notice of such meeting of stockholders or Board of Directors as the case may be. Changes to the Bylaws or the adoption of new Bylaws must be approved by either the holders of at least 66-2/3% of the combined voting power of the then-outstanding shares of Voting Stock, voting together as a single class, or by the affirmative vote of directors constituting two-thirds or more of the entire Board of Directors.

Section 2 . Entire Board of Directors . As used in this Article IX and in these Bylaws generally, the term “entire Board of Directors” means the total number of directors which the Corporation would have if there were no vacancies.

Exhibit 4.19

DEVON OEI OPERATING, INC.
as Issuer,

DEVON ENERGY PRODUCTION COMPANY, L.P.
as Successor Guarantor

and

THE BANK OF NEW YORK TRUST COMPANY, N.A.
as Trustee

FIRST SUPPLEMENTAL INDENTURE

Dated as of December 31, 2005

Supplementing the Indenture dated as of September 28, 2001

4 ³ / 8 % Senior Notes due 2007

7 ¹ / 4 % Senior Notes due 2011

This FIRST SUPPLEMENTAL INDENTURE, dated as of December 31, 2005 (this “ First Supplemental Indenture ”), is by and among Devon OEI Operating, Inc. (f/k/a Ocean Energy, Inc.), a Delaware corporation (the “ Company ”), Devon Energy Production Company, L.P., an Oklahoma limited partnership (the “ Guarantor ”), and The Bank of New York Trust Company, N.A., as successor to The Bank of New York, as trustee (the “ Trustee ”).

RECITALS OF THE COMPANY

WHEREAS, the Company and Devon Louisiana Corporation (f/k/a Ocean Energy, Inc.), a Louisiana corporation (“ OEI Sub ”), executed and delivered to the Trustee the Senior Indenture, dated as of September 28, 2001 (the “Indenture”); and

WHEREAS, the Company has issued, pursuant to the Indenture, two series of notes, its 7 ¹ / 4 % Senior Notes due 2011 and its 4-3/8% Senior Notes due 2007 (collectively, the “ Securities ”) and payment thereof has been guaranteed by OEI Sub as and to the extent set forth in Article Thirteen of the Indenture; and

WHEREAS, the Guarantor is the surviving entity of the merger (the “ Merger ”) of OEI Sub with and into the Guarantor that occurred on December 31, 2005; and

WHEREAS, Section 13.3 of the Indenture, requires the Person (if other than OEI Sub) surviving a merger involving OEI Sub to assume, pursuant to a supplemental indenture in a form reasonably satisfactory to the Trustee, all of the obligations of OEI Sub under the Securities and the Indenture.

NOW, THEREFORE, the Company, the Guarantor and the Trustee mutually covenant and agree:

ARTICLE 1
ASSUMPTION

The Guarantor hereby assumes all of the obligations of OEI Sub under the Securities and the Indenture.

ARTICLE 2
MISCELLANEOUS PROVISIONS

2.1 Relation to the Indenture . The provisions of this First Supplemental Indenture shall become effective as of the effective time of the Merger. This First Supplemental Indenture and all terms and provisions contained in it shall form a part of the Indenture as fully and with the same effect as if all such terms and provisions had been set forth in the Indenture. The Indenture is hereby ratified and confirmed in all respects and shall remain and continue in full force and effect in accordance with the provisions thereof, as supplemented by this First Supplemental Indenture. The Indenture and this First Supplemental Indenture shall be read, taken and construed together as one instrument.

2.2 Responsibility for Recitals, Etc . The recitals in this First Supplemental Indenture shall be taken as statements of the Company, and the Trustee assumes no responsibility for the

correctness thereof. The Trustee makes no representations as to the validity or sufficiency of this First Supplemental Indenture.

2.3 Provisions Binding on Guarantor’s Successors . All of the covenants, stipulations, promises and agreements in this First Supplemental Indenture by the Guarantor shall bind its successors and assigns, whether so expressed or not.

2.4 New York Contract . THIS FIRST SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK WITHOUT REGARD TO CONFLICTS OF LAWS AND PRINCIPLES THEREOF.

2.5 Execution and Counterparts . This First Supplemental Indenture may be executed with counterpart signature pages, each of which shall be an original but both of which shall together constitute but one and the same instrument.

2.6 Capitalized Terms . Capitalized terms not otherwise defined in this First Supplemental Indenture shall have the respective meanings assigned to them in the Indenture.

[Signature page follows]

IN WITNESS WHEREOF, the Company, the Guarantor and the Trustee have caused this First Supplemental Indenture to be duly executed as of the date first above written.


		DEVON OEI OPERATING, INC., a Delaware corporation

		By: Name:		/s/ Jeffrey A. Agosta Jeffrey A. Agosta
		Title:		Vice President and Treasurer

		DEVON ENERGY PRODUCTION COMPANY, L.P., an Oklahoma limited partnership

		By: Name:		/s/ Jeffrey A. Agosta Jeffrey A. Agosta
		Title:		Vice President and Treasurer

		THE BANK OF NEW YORK TRUST COMPANY, N.A., as Trustee

		By: Name:		/s/ John C. Stohlmann John C. Stohlmann
		Title:		Vice President

Exhibit 4.23

DEVON OEI OPERATING, INC.
as Issuer,

DEVON ENERGY PRODUCTION COMPANY, L.P.
as Successor Guarantor

and

WELLS FARGO BANK, N.A.
as Trustee

THIRD SUPPLEMENTAL INDENTURE

Dated as of January 23, 2006

Supplementing the Indenture dated as of July 8, 1998

8 ¹ / 4 % Senior Notes due 2018

This THIRD SUPPLEMENTAL INDENTURE, dated as of January 23, 2006 (this “ Third Supplemental Indenture ”), is by and among Devon OEI Operating, Inc. (f/k/a Ocean Energy, Inc.), a Delaware corporation (the “ Company ”), as successor to Ocean Energy Inc., (f/k/a Seagull Energy Corporation), a Texas corporation (“ Old Ocean ”), Devon Energy Production Company, L.P., an Oklahoma limited partnership (the “ New Subsidiary Guarantor ”), and Wells Fargo Bank, N.A., as successor to Norwest Bank Minnesota, National Association, as trustee (the “ Trustee ”). Capitalized terms used herein and not defined herein shall have the meanings ascribed to them in the Indenture (as defined below).

RECITALS OF THE COMPANY

WHEREAS, Ocean Energy, Inc., a Delaware corporation (“ Old OEI ”), as issuer, and Devon Louisiana Corporation (f/k/a Ocean Energy Inc.), a Louisiana corporation (“ OEI Sub ”), as subsidiary guarantor, executed and delivered to the Trustee the Indenture, dated as of July 8, 1998 (the “ Indenture ”), providing for the issuance of an aggregate principal amount of $125,000,000 of 8 ¹ / 4 % Senior Notes due 2018 (the “ Notes ”); and

WHEREAS, following the merger of Old OEI with and into Old Ocean, Old Ocean, as successor to Old OEI, and OEI Sub, as subsidiary guarantor, executed and delivered the First Supplemental Indenture, dated as of March 30, 1999, to the Trustee, in which Old Ocean expressly assumed all of the obligations of and was substituted for Old OEI under the Indenture; and

WHEREAS, following the merger of Old Ocean with and into the Company, the Company, as successor to Old Ocean, and OEI Sub, as subsidiary guarantor, executed and delivered the Second Supplemental Indenture, dated as of May 9, 2001, to the Trustee, in which the Company expressly assumed all of the obligations of and was substituted for Old Ocean under the Indenture; and

WHEREAS, the New Subsidiary Guarantor is the surviving entity of the merger (the “ Merger ”) of OEI Sub with and into the New Subsidiary Guarantor that occurred on December 31, 2005; and

WHEREAS, Section 10.3 of the Indenture, requires the Person (if other than OEI Sub) surviving a merger involving OEI Sub to assume, pursuant to a supplemental indenture in a form reasonably satisfactory to the Trustee, all of the obligations of OEI Sub under the Notes and the Indenture; and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Third Supplemental Indenture.

NOW THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Company, the New Subsidiary Guarantor and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

ARTICLE 1
AGREEMENT TO GUARANTEE

1.1 Guarantee of New Subsidiary Guarantor . Subject to Section 10.05 of the Indenture, the New Subsidiary Guarantor hereby, jointly and severally with all other Subsidiary Guarantors, unconditionally guarantees to each Holder of a Note authenticated and delivered by the Trustee and to the Trustee and its successors and assigns, the Notes and the Obligations of the Company under the Notes or under the Indenture, that: (a) the principal of, premium, if any, and interest on the Notes will be promptly paid in full when due, subject to any applicable grace period, whether at maturity, by acceleration, redemption or otherwise, and interest on overdue principal, premium, if any (to the extent permitted by law), and interest on any interest, if any, on the Notes and all other payment Obligations of the Company to the Holders or the Trustee under the Indenture or under the Notes will be promptly paid in full and performed, all in accordance with the terms hereof; and (b) in case of any extension of time of payment or renewal of any Notes or any of such other Obligations, the same will be promptly paid in full when due or performed in accordance with the terms of the extension or renewal, subject to any applicable grace period, whether at stated maturity, by acceleration, redemption or otherwise. Failing payment when so due of any amount so guaranteed or any performance so guaranteed for whatever reason, the Subsidiary Guarantors will be jointly and severally obligated to pay the same immediately.

The obligations of the Subsidiary Guarantors to the Holders and to the Trustee pursuant to this Third Supplemental Indenture and the Indenture are expressly set forth in Article X of the Indenture, and reference is hereby made to such Indenture for the precise terms of this Subsidiary Guarantee. The terms of Article X of the Indenture are incorporated herein by reference. This Subsidiary Guarantee is subject to release as and to the extent provided in Sections 4.07(c), 4.07(d) and 10.04 of the Indenture.

ARTICLE 2
MISCELLANEOUS PROVISIONS

2.1 Relation to the Indenture . The provisions of this Third Supplemental Indenture shall become effective as of the effective time of the Merger. This Third Supplemental Indenture and all terms and provisions contained in it shall form a part of the Indenture as fully and with the same effect as if all such terms and provisions had been set forth in the Indenture. The Indenture, as previously supplemented, is hereby ratified and confirmed in all respects and shall remain and continue in full force and effect in accordance with the provisions thereof, as supplemented by this Third Supplemental Indenture. The Indenture, as previously supplemented, and this Third Supplemental Indenture shall be read, taken and construed together as one instrument.

2.2 No Recourse Against Others . No past, present or future director, officer, employee, incorporator, partner, member, shareholder or agent of the New Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company or any Subsidiary Guarantor under the Notes, any Subsidiary Guarantees, the Indenture or this Third Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

2.3 Responsibility for Recitals, Etc . The recitals in this Third Supplemental Indenture shall be taken as statements of the Company and the New Subsidiary Guarantor, and the Trustee assumes no responsibility for the correctness thereof. The Trustee makes no representations as to the validity or sufficiency of this Third Supplemental Indenture.

2.4 Provisions Binding on New Subsidiary Guarantor’s Successors . All of the covenants, stipulations, promises and agreements in this Third Supplemental Indenture by the New Subsidiary Guarantor shall bind its successors and assigns, whether so expressed or not.

2.5 New York Contract . THIS THIRD SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK WITHOUT REGARD TO CONFLICTS OF LAWS AND PRINCIPLES THEREOF.

2.6 Execution and Counterparts . This Third Supplemental Indenture may be executed with counterpart signature pages, each of which shall be an original but both of which shall together constitute but one and the same instrument.

2.7 Effect of Headings . The Section headings herein are for convenience only and shall not affect the construction hereof.

[Signature page follows]

IN WITNESS WHEREOF, the Company, the New Subsidiary Guarantor and the Trustee have caused this Third Supplemental Indenture to be duly executed as of the date first above written.


		DEVON OEI OPERATING, INC.,
		a Delaware corporation

		By:		/s/ Jeffrey A. Agosta

		Name:		Jeffrey A. Agosta
		Title:		Vice President and Treasurer

		DEVON ENERGY PRODUCTION COMPANY, L.P.,
		an Oklahoma limited partnership

		By:		/s/ Jeffrey A. Agosta

		Name:		Jeffrey A. Agosta
		Title:		Vice President and Treasurer

		WELLS FARGO BANK, N.A., as Trustee

		By:		/s/ Lynn M. Steiner

		Name: Title:		Lynn M. Steiner Vice President

Exhibit 4.27

DEVON OEI OPERATING, INC.
as Issuer,

DEVON ENERGY PRODUCTION COMPANY, L.P.
as Successor Guarantor

and

THE BANK OF NEW YORK TRUST COMPANY, N.A.,
as Trustee

THIRD SUPPLEMENTAL INDENTURE

Dated as of December 31, 2005

Supplementing the Indenture dated as of September 1, 1997

7 ¹ / 2 % Senior Notes due 2027

This THIRD SUPPLEMENTAL INDENTURE, dated as of December 31, 2005 (this “ Third Supplemental Indenture ”), is by and among Devon OEI Operating, Inc. (f/k/a Ocean Energy, Inc.), a Delaware corporation (the “ Company ”), as successor to Ocean Energy, Inc. (f/k/a Seagull Energy Corporation), a Texas Corporation (“ Old Ocean ”), Devon Energy Production Company, L.P., an Oklahoma limited partnership (the “ Guarantor ”), and The Bank of New York Trust Company, N.A., as successor to The Bank of New York, as trustee (the “ Trustee ”).

RECITALS OF THE COMPANY

Whereas, Old Ocean, as issuer, executed and delivered to the Trustee the Senior Indenture, dated as of September 1, 1997 (the “ Indenture ”), providing for the issuance of an aggregate principal amount of $150,000,000 of 7 ¹ / 2 % Senior Notes due 2027 (the “ Securities ”); and

WHEREAS, Old Ocean, as issuer, and Devon Louisiana Corporation (f/k/a Ocean Energy, Inc.), a Louisiana corporation (“ OEI Sub ”), as subsidiary guarantor, executed and delivered the First Supplemental Indenture, dated as of March 30, 1999, to the Trustee, adding Article Thirteen to the Indenture and providing for the creation of a Subsidiary Guarantee by OEI Sub; and

WHEREAS, following the merger of Old Ocean with and into the Company, the Company, as issuer, and OEI Sub, as subsidiary guarantor, executed and delivered the Second Supplemental Indenture, dated as of May 9, 2001, to the Trustee, providing for the assumption by the Company of all of the obligations of Old Ocean under the Securities and the Indenture; and

WHEREAS, the Guarantor is the surviving entity of the merger (the “ Merger ”) of OEI Sub with and into the Guarantor that occurred on December 31, 2005; and

NOW, THEREFORE, the Company, the Guarantor and the Trustee mutually covenant and agree:

ARTICLE 1
ASSUMPTION

The Guarantor hereby assumes all of the obligations of OEI Sub under the Securities and the Indenture.

ARTICLE 2
MISCELLANEOUS PROVISIONS

2.2 Responsibility for Recitals, Etc . The recitals in this Third Supplemental Indenture shall be taken as statements of the Company, and the Trustee assumes no responsibility for the correctness thereof. The Trustee makes no representations as to the validity or sufficiency of this Third Supplemental Indenture.

2.3 Provisions Binding on Guarantor’s Successors . All of the covenants, stipulations, promises and agreements in this Third Supplemental Indenture by the Guarantor shall bind its successors and assigns, whether so expressed or not.

2.4 New York Contract . THIS THIRD SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK WITHOUT REGARD TO CONFLICTS OF LAWS AND PRINCIPLES THEREOF.

2.5 Execution and Counterparts . This Third Supplemental Indenture may be executed with counterpart signature pages, each of which shall be an original but both of which shall together constitute but one and the same instrument.

2.6 Capitalized Terms . Capitalized terms not otherwise defined in this Third Supplemental Indenture shall have the respective meanings assigned to them in the Indenture.

[Signature page follows]

IN WITNESS WHEREOF, the Company, the Guarantor and the Trustee have caused this Third Supplemental Indenture to be duly executed as of the date first above written.


		DEVON OEI OPERATING, INC.,
		a Delaware corporation

		By:		/s/ Jeffrey A. Agosta

		Name:		Jeffrey A. Agosta
		Title:		Vice President and Treasurer

		DEVON ENERGY PRODUCTION COMPANY, L.P.,
		an Oklahoma limited partnership

		By:		/s/ Jeffrey A. Agosta

		Name:		Jeffrey A. Agosta
		Title:		Vice President and Treasurer

		THE BANK OF NEW YORK TRUST COMPANY, N.A.,
		as Trustee

		By:		/s/ John C. Stohlmann

		Name:		John C. Stohlmann
		Title:		Vice President

Exhibit 12

RATIOS OF EARNINGS TO FIXED CHARGES AND COMBINED FIXED CHARGES AND
PREFERRED STOCK DIVIDENDS
December 31, 2005


	Years Ended December 31,
	2005		2004		2003		2002			2001
	(In millions, except ratios)
EARNINGS:
Adjusted earnings (loss) from continuing operations before income taxes	$	4,506		3,240		2,203		(135	)		27
Add fixed charges (see below)		616		565		569		549			229

Adjusted earnings	$	5,122		3,805		2,772		414			256


FIXED CHARGES AND PREFERRED STOCK DIVIDENDS:
Gross interest expense		604		545		552		537			223
Dividends on preferred stock of a subsidiary		—		—		3		—			—
Estimated interest component of operating lease payments		12		20		14		12			6

Fixed charges		616		565		569		549			229
Preferred stock requirements, pre-tax		15		15		16		16			16

Combined fixed charges and preferred stock dividends	$	631		580		585		565			245


Ratio of earnings to fixed charges		8.32		6.73		4.87		N/A			1.12

Ratio of earnings to combined fixed charges and preferred stock dividends		8.12		6.56		4.74		N/A			1.05

Insufficiency of earnings to cover fixed charges		N/A		N/A		N/A		135			N/A

Insufficiency of earnings to cover combined fixed charges and preferred stock dividends		N/A		N/A		N/A		151			N/A

EXHIBIT 21

DEVON ENERGY CORPORATION

Significant Subsidiaries


1.		Devon Energy Corporation (Oklahoma), an Oklahoma corporation;

2.		Devon Energy Production Company, L.P., an Oklahoma limited partnership;

3.		Devon Canada Corporation, a Nova Scotia corporation;

4.		Devon Canada, a general partnership registered in Alberta;

5.		Devon ARL Corporation, an Nova Scotia corporation;

6.		Devon Operating Company Ltd., an Alberta corporation;

7.		Devon OEI Operating, Inc., a Delaware corporation;

8.		Devon AXL, a general partnership registered in Alberta;

9.		Northstar Energy Corporation, a Nova Scotia corporation; and

10.		Devon Gas Services, L.P., a Delaware limited partnership.

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors
Devon Energy Corporation:

We consent to the incorporation by reference in the registration statements (File Nos. 333-68694, 333-32214, 333-47672, 333-44702, 333-39908, 333-85553, 333-104922, 333-104933, 333-103679 and 333-127630) on Form S-8 and the Registration Statements (File Nos. 333-85211, 333-50036- and 333-100308) on Form S-3 of Devon Energy Corporation of our reports dated February 28, 2006, with respect to the consolidated balance sheets of Devon Energy Corporation 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, management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005 and the effectiveness of internal control over financial reporting as of December 31, 2005, which reports appear in the December 31, 2005 Annual Report on Form 10-K of Devon Energy Corporation.

Our audit report on the consolidated financial statements refers to a change in the method of accounting for asset retirement obligations in 2003.

/s/ KPMG LLP

Oklahoma City, Oklahoma
February 28, 2006

Exhibit 23.2

ENGINEER’S CONSENT

We consent to incorporation by reference in the Registration Statements (File Nos. 333-68694, 333-32214, 333-47672, 333-44702, 333-39908, 333-85553, 333-104922, 333-104933, 333-103679 and 333-127630) on Form S-8, and the Registration Statements (File Nos. 333-85211, 333-50036 and 333-100308) on Form S-3 of Devon Energy Corporation of the reference to our reports for Devon Energy Corporation, which appears in the December 31, 2005 annual report on Form 10-K of Devon Energy Corporation.


	LAROCHE PETROLEUM CONSULTANTS, LTD.
	By:	/s/ William M. Kazmann
		William M. Kazmann
		Partner

March 2, 2006

Exhibit 23.3

CONSENT OF RYDER SCOTT COMPANY, L.P.



	/s/ Ryder Scott Company, L.P.

	RYDER SCOTT COMPANY, L.P.

Houston, Texas
February 28, 2006

Exhibit 23.4

ENGINEER’S CONSENT


	AJM PETROLEUM CONSULTANTS
	By:	/s/ Robin G. Bertram
		Robin G. Bertram, P.Eng.
		Vice President, Engineering

March 1, 2006

Exhibit 31.1

Certification Pursuant to Rule 13a-15(e) and 15d-15(e) As Adopted
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2005

I, J. Larry Nichols, certify that:

1. I have reviewed this annual report on Form 10-K of Devon Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



	/s/ J. Larry Nichols
	J. Larry Nichols
Date: February 27, 2006	Chief Executive Officer

Exhibit 31.2

Certification Pursuant to Rule 13a-15(e) and 15d-15(e) As Adopted
Pursuant to Section 302 of the Sarbanes-Oxley Act of 2005

I, Brian J. Jennings, certify that:

1. I have reviewed this annual report on Form 10-K of Devon Energy Corporation;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



	/s/ Brian J. Jennings
	Brian J. Jennings
Date: February 27, 2006	Chief Financial Officer

Exhibit 32.1

Certification Pursuant to 18 U.S.C. Section 1350 as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the annual report of Devon Energy Corporation (“Devon”) on Form 10-K for the period ended December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, J. Larry Nichols, Chief Executive Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

	(1)		The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	(2)		The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.


		/s/ J. Larry Nichols

		J. Larry Nichols
		Chief Executive Officer

Date: February 27, 2006

Exhibit 32.2

Certification Pursuant to 18 U.S.C. Section 1350 as Adopted
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the annual report of Devon Energy Corporation (“Devon”) on Form 10-K for the period ended December 31, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brian J. Jennings, Chief Financial Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

	(1)		The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	(2)		The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.


		/s/ Brian J. Jennings

		Brian J. Jennings
		Chief Financial Officer
Date: February 27, 2006


	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.


		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.


	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.